Injection fluids comprising an anionic surfactant for treating unconventional formations

ABSTRACT

Embodiments of the disclosure include compositions and methods that stabilize a injection fluid when exposed to reservoir conditions, reducing formation damage and increasing the amount of hydrocarbon recovered. Specifically, the formulation is a single-phase liquid surfactant package which comprises an anionic surfactant and optionally one or more secondary surfactants.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority to U.S. ProvisionalApplication 62/538,883, filed Jul. 31, 2017, which is incorporated byreference herein in its entirety.

TECHNICAL FIELD

The present disclosure relates generally to unconventional reservoirs,and more specifically to using low particle size injection fluids fortreating unconventional subterranean formations.

BACKGROUND

Wells in unconventional or “tight” formations typically undergo multiplefracture stages which are completed in series during fracturingoperations. To prop open fractures during such operations, specificcocktails of injection fluid are employed to viscosify the injectionfluid and help transport proppant to the far reaches of the fracture,thereby establishing a larger propped fracture network and increasedstimulated reservoir volume.

Typical injection fluids can include over a dozen chemical componentswhich are mixed into a surface water, typically brackish or recycledproduction water. During fracturing operations (completions stage) of anunconventional horizontal well, the injection fluids with these additivechemicals are pumped down the well in large quantities (˜10,000 bbls)and the injection fluid contacts the surfaces of the fracture network(FIG. 1A prior to fluid injection; FIG. 1B during fluid injection).Current injection fluids contain dirty water, unfiltered surface water,and/or oil carry-over in surface water. The condition of the injectionfluid is such that it can be unstable when exposed to reservoirconditions, such as high temperature, high formation brine salinity,high divalent ion concentrations, etc. The unstable injection fluid cancause a loss in well productivity due to formation damage (FIG. 1C). Theterm “formation damage” in this context is used to refer to plugging offmatrix permeability (which can be on the order of 100's of nano-Darcies)in the formation thus obstructing or hindering fluid flow, for example,due to the suspended particles in the injection fluid precipitating outof solution and causing the plugging.

Embodiments of the disclosure include compositions and methods thatstabilize the injection fluid when exposed to reservoir conditions,reducing formation damage and increasing the amount of hydrocarbonrecovered.

SUMMARY

Described herein are methods for treating unconventional subterraneanformations with fluids. The methods described herein can comprisecombining a single-phase liquid surfactant package comprising a primarysurfactant with an aqueous-based injection fluid to form a low particlesize injection fluid; and introducing the low particle size injectionfluid into the unconventional subterranean formation. The primarysurfactant can comprise an anionic surfactant comprising a hydrophobictail comprising from 6 to 60 carbon atoms. The low particle sizeinjection fluid can have a maximum particle size of less than 0.1micrometers in diameter in particle size distribution measurementsperformed at a temperature and salinity of the unconventionalsubterranean formation.

In some embodiments, the low particle size injection fluid can furthercomprise a proppant. In these embodiments, the maximum particle size ofless than 0.1 micrometers can be measured exclusive of the proppant.

In some embodiments, the primary surfactant can comprise from 10% to 90%by weight of the single-phase liquid surfactant package. The primarysurfactant can comprise, for example a sulfonate, a disulfonate, apolysulfonate, a sulfate, a disulfate, a polysulfate, a sulfosuccinate,a disulfosuccinate, a polysulfosuccinate, a carboxylate, adicarboxylate, a polycarboxylate, or any combination thereof. In someexamples, the primary surfactant can comprise a C10-C30 internal olefinsulfonate, a C10-C30 isomerized olefin sulfonate, a C10-C30 alfa olefinsulfonate, a C8-C30 alkyl benzene sulfonate (ABS), a sulfosuccinatesurfactant, or any combination thereof. In some examples, the primarysurfactant can comprise a branched or unbranchedC6-C32:PO(0-65):EO(0-100)-carboxylate (e.g., a branched or unbranchedC6-C30:PO(30-40):EO(25-35)-carboxylate, a branched or unbranchedC6-C12:PO(30-40):EO(25-35)-carboxylate, a branched or unbranchedC6-C30:EO(8-30)-carboxylate, or any combination thereof). In someexamples, the primary surfactant can comprise a surfactant defined bythe formula below

R¹—R²—R³

wherein IV comprises a branched or unbranched, saturated or unsaturated,cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atomsand an oxygen atom linking R¹ and R²; R² comprises an alkoxylated chaincomprising at least one oxide group selected from the group consistingof ethylene oxide, propylene oxide, butylene oxide, and combinationsthereof and R³ comprises a branched or unbranched hydrocarbon chaincomprising 2-12 carbon atoms and from 2 to 5 carboxylate groups. In someexamples, the primary surfactant can comprise a surfactant defined bythe formula below

wherein R⁴ is a branched or unbranched, saturated or unsaturated, cyclicor non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms; and Mrepresents a counterion (e.g., Na⁺, K⁺).

In some embodiments, the single-phase liquid surfactant package canoptionally further comprise one or more secondary surfactants. The oneor more secondary surfactants can comprise from 10% to 90% by weight ofthe single-phase liquid surfactant package. The one or more secondarysurfactants can comprise one or more non-ionic surfactants, one or moreadditional anionic surfactants, one or more cationic surfactants, one ormore zwitterionic surfactants, or any combination thereof. In someembodiments, the one or more secondary surfactants can comprise anon-ionic surfactant. In some examples, the non-ionic surfactant cancomprise a branched or unbranched C6-C32:PO(0-65):EO(0-100) (e.g., abranched or unbranched C6-C30:PO(30-40):EO(25-35), a branched orunbranched C6-C12:PO(30-40):EO(25-35), a branched or unbranchedC6-30:EO(8-30), or any combination thereof).

The aqueous-based injection fluid can comprise any type of water,treated or untreated, and can vary in salt content. For example, theaqueous-based injection fluid can comprise sea water, brackish water,fresh water, flowback or produced water, wastewater (e.g., reclaimed orrecycled), river water, lake or pond water, aquifer water, brine (e.g.,reservoir or synthetic brine), or any combination thereof. In someembodiments, the aqueous-based injection fluid can comprise slickwater.

In some embodiments, the mean particle size distribution of the lowparticle size injection fluid can be less than an average pore size of arock matrix in the unconventional subterranean formation. In someembodiments, the mean particle size distribution of the low particlesize injection fluid can be less than 0.05 micrometer in diameter whenmeasured at a temperature and salinity of the unconventionalsubterranean formation. In some embodiments, the aqueous-based injectionfluid can have a mean particle size distribution of greater than 10micrometers prior to the addition of the single-phase liquid surfactantpackage. In some embodiments, the mean particle size distribution of thelow particle size injection fluid can be at least 10 μm smaller than amean particle size distribution of the aqueous-based injection fluid. Insome embodiments, the low particle size injection fluid precipitates outfewer solid particles than the aqueous-based injection fluid whenintroduced into the rock matrix.

Combination of the single-phase liquid surfactant package with theaqueous-based injection fluid can lower the particle size distributionof the aqueous-based injection fluid when measured at the temperatureand salinity of the unconventional subterranean formation.

In some embodiments, the low particle size injection fluid can beintroduced at a wellhead pressure of from 0 PSI to 30,000 PSI (e.g.,from 6,000 PSI to 30,000 PSI, or from 5,000 PSI to 10,000 PSI). Theunconventional subterranean formation can have a temperature of from 75°F. to 350° F. (e.g., from 150° F. to 250° F.), a salinity of at least5,000 ppm TDS (e.g., at least 100,000 ppm TDS, such as from 100,000 ppmto 300,000 ppm TDS), a permeability of less than 25 mD (e.g., from 10 to0.1 millidarcy (mD)), or any combination thereof.

Optionally, the single-phase liquid surfactant package, the low particlesize injection fluid, the aqueous-based injection fluid, or anycombination thereof can include one or more additional components. Forexample, the single-phase liquid surfactant package, the low particlesize injection fluid, the aqueous-based injection fluid, or anycombination thereof can further comprise an acid, a polymer, a frictionreducer, a gelling agent, a crosslinker, a scale inhibitor, a breaker, apH adjusting agent, a non-emulsifier agent, an iron control agent, acorrosion inhibitor, a biocide, a clay stabilizing agent, a proppant, awettability alteration chemical, a co-solvent (e.g., a C1-C5 alcohol, oran alkoxylated C1-C5 alcohol), or any combination thereof. In certainembodiments, the aqueous-based injection fluid can comprise an acid(e.g., at least 10% acid, such as from 10% to 20% by weight acid).

Also provided are methods for treating an unconventional subterraneanformation with a fluid that comprise providing an aqueous-basedinjection fluid for treating the unconventional subterranean formation,the unconventional subterranean formation having a rock matrix with anaverage pore size less than 0.1 micrometer; and adding an anionicsurfactant to the aqueous-based injection fluid to form a low particlesize injection fluid; and introducing the low particle size injectionfluid into the rock matrix of the unconventional subterranean formation.The low particle size injection fluid can have a maximum particle sizeof less than 0.1 micrometer in diameter particle size distributionmeasurement when measured at a temperature and salinity of theunconventional subterranean formation.

Also provided are methods for fracturing an unconventional subterraneanformation with a fluid. These methods can comprise combining asingle-phase liquid surfactant package comprising a primary surfactantwith an aqueous-based injection fluid to form a low particle sizeinjection fluid; and injecting the low particle size injection fluidthrough a wellbore and into the unconventional subterranean formation ata sufficient pressure and at a sufficient rate to fracture theunconventional subterranean formation. The primary surfactant cancomprise an anionic surfactant comprising a hydrophobic tail comprisingfrom 6 to 60 carbon atoms. The low particle size injection fluid canhave a maximum particle size of less than 0.1 micrometers in diameter inparticle size distribution measurements performed at a temperature andsalinity of the unconventional subterranean formation.

The wellbore can comprise a vertical trajectory, a horizontaltrajectory, or any combination thereof. In some embodiments, the methodcan comprise performing a fracturing operation on a region of theunconventional subterranean formation proximate to a new wellbore. Insome embodiments, the method can comprise performing a fracturingoperation on a region of the unconventional subterranean formationproximate to an existing wellbore. In some embodiments, the method cancomprise performing a refracturing operation on a previously fracturedregion of the unconventional subterranean formation proximate to a newwellbore. In some embodiments, the method can comprise performing arefracturing operation on a previously fractured region of theunconventional subterranean formation proximate to an existing wellbore.In some embodiments, the method can comprise performing a fracturingoperation on a naturally fractured region of the unconventionalsubterranean formation proximate to a new wellbore. In some embodiments,the method can comprise performing a fracturing operation on a naturallyfractured region of the unconventional subterranean formation proximateto an existing wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawings illustrate only example embodiments of methods, systems,and devices for stabilizing injection fluids and are therefore not to beconsidered limiting of its scope, as aspects of the disclosure may admitto other equally effective embodiments. The elements and features shownin the drawings are not necessarily to scale, emphasis instead beingplaced upon clearly illustrating the principles of the exampleembodiments. Additionally, certain dimensions or positionings may beexaggerated to help visually convey such principles. In the drawings,reference numerals designate like or corresponding, but not necessarilyidentical, elements.

FIGS. 1A-1C illustrate some steps of a typical fracturing process usingconventional injection fluids in an unconventional reservoir. FIG. 1Ashows a portion of the unconventional reservoir prior to injection ofconventional injection fluids. FIG. 1B illustrates conventionalinjection fluids being injected into the portion of the unconventionalreservoir shown in FIG. 1A. FIG. 1C shows trapped particles which plugoff matrix permeability in the portion of the unconventional reservoir,left by conventional injection fluids after the injection fluid isreleased from the reservoir.

FIGS. 2A-2C illustrate injection of low particle size injection fluidsin a portion of an unconventional reservoir. FIG. 2A shows a portion ofthe unconventional reservoir prior to the injection of low particle sizeinjection fluids. FIG. 2B illustrates the injection of low particle sizeinjection fluids into the portion of the unconventional reservoir shownin FIG. 2A where the insoluble particles are minimized and the chemicalspenetrate the rock matrix. FIG. 2C shows the unconventional reservoirafter the low particle size injection fluid is released from thereservoir leaving an increased transmissibility and improvedproductivity compared to use of conventional injection fluids.

FIG. 3A is a schematic illustration of methods of preparing low particlesize injection fluids using the single-phase liquid surfactant packagesdescribed herein. The system includes a conventional surface blendingsystem to accommodate the preparation of low particle size injectionfluids for use in a variety of operations, including fracturingoperations (e.g., fracturing a formation that was not previouslyfractured such as hydraulically fracturing a formation for the firsttime) and refracturing operations (e.g., fracturing a formation that waspreviously fractured such as hydraulically fracturing a formation asubsequent time). The system may also be used for completion of newwells.

FIG. 3B is a schematic illustration of alternative methods of preparinglow particle size injection fluids using the single-phase liquidsurfactant packages described herein. The system is simplified for usein the stimulation of a fractured formation with low particle sizeinjection fluids (e.g., naturally fractured formation or formation thathas undergone a fracturing operation or formation that has undergone arefracturing operation).

FIG. 4 is a photograph of four containers with, from left to right,slickwater and a single-phase liquid surfactant package (SPLC1),slickwater and a second single-phase liquid surfactant package (SPLC2),slickwater and a third single-phase liquid surfactant package (SPLC3),and slickwater only.

FIG. 5 is a photograph of containers with increasing salinity overbackground brine using slickwater and a single-phase liquid surfactantpackage (SPLC1) in, from left to right, SPLC1 only, +1% NaCl, +2.5%NaCl, +5% NaCl, +10% NaCl, +15% NaCl, and slickwater only.

FIG. 6 is a photograph of three containers comprising differentconcentrations of a single-phase liquid surfactant package (SPLC1), fromleft to right, 0.75 wt % SPLC1, 0.375 wt % SPLC1, and slickwater onlytested at 75° C. (167° F.).

FIG. 7 is a photograph of two containers, from left to right, comprisinga mixture of a single-phase liquid surfactant package (SPLC1) and aninjection fluid comprising sand at 75° C. (167° F.), and an injectionfluid comprising sand only tested at 75° C. (167° F.).

FIG. 8 is the particle size distribution of slickwater only (solid line)and slickwater plus a C9-11 ethoxylated alcohol surfactant (dashedline), and slickwater plus benzenesulfonic acid,decyl(sulfophenoxy)-disodium salt (dotted line).

FIG. 9 is the particle size distribution of slickwater only (solidcurved line), slickwater plus benzenesulfonic acid,decyl(sulfophenoxy)-disodium salt and a Guerbet C10 ethoxylated alcoholsurfactant (dotted straight line), and slickwater plus benzenesulfonicacid, decyl(sulfophenoxy)-disodium salt and a C9-11 ethoxylated alcoholsurfactant (dashed straight line having the same frequency value andbeing coincident with the dashed straight line for the version with theGuerbet non-ionic surfactant).

FIG. 10 is the particle size distribution of slickwater only (solidcurved line), slickwater plus a Guerbet C10 ethoxylated alcoholsurfactant (dashed line), and slickwater plus benzenesulfonic acid,decyl(sulfophenoxy)-disodium salt surfactant (dotted straight line).

FIG. 11 is a photograph of three containers with, from left to right,slickwater only, slickwater and a single-phase liquid surfactant package(SPLC4), and slickwater and internal olefin sulfonate (IOS).

FIG. 12 is the particle size distribution of slickwater only (solidcurved line), slickwater plus isomerized olefin sulfonate (IOS) and aGuerbet C10 ethoxylated alcohol surfactant (dashed straight line),slickwater plus isomerized olefin sulfonate (dashed straight line havingthe same frequency value and being coincident with the dashed straightline for the version with the Guerbet non-ionic surfactant).

FIG. 13 is an overlay profile of high-performance liquid chromatography(HPLC) for ethoxylated alcohol in deionized (DI) water and 15%hydrochloric acid (HCL) after being heated 3 days at 75° C. (167° F.).

FIG. 14 a graph of fluid production at a tank battery level, whichencompasses five horizontal wells, four of which were stimulated usingan example LPS injection fluid. The dots represent crude oil flowproduction and the solid line represents a decline curve extrapolationfit that was performed for the tank battery prior to injection of theLPS injection fluid.

FIG. 15 shows tracer response curves for five horizontal wells, four ofwhich were stimulated using an example LPS injection fluid. Injectionfluid for each well was traced with a different chemical tracer inefforts to diagnose and interpret fluid production results. Tracerconcentrations were measured from produced fluid samples. The quantityof tracer chemicals recovered compared to the total quantity injectedfor the comparison well with brine injection was much higher compared tothe four wells injected with LPS fluid.

DETAILED DESCRIPTION OF EXAMPLE EMBODIMENTS

The example embodiments discussed herein are directed to compositionsand methods of stabilizing injection fluids.

As used in this specification and the following claims, the terms“comprise” (as well as forms, derivatives, or variations thereof, suchas “comprising” and “comprises”) and “include” (as well as forms,derivatives, or variations thereof, such as “including” and “includes”)are inclusive (i.e., open-ended) and do not exclude additional elementsor steps. For example, the terms “comprise” and/or “comprising,” whenused in this specification, specify the presence of stated features,integers, steps, operations, elements, and/or components, but do notpreclude the presence or addition of one or more other features,integers, steps, operations, elements, components, and/or groupsthereof. Accordingly, these terms are intended to not only cover therecited element(s) or step(s), but may also include other elements orsteps not expressly recited. Furthermore, as used herein, the use of theterms “a” or “an” when used in conjunction with an element may mean“one,” but it is also consistent with the meaning of “one or more,” “atleast one,” and “one or more than one.” Therefore, an element precededby “a” or “an” does not, without more constraints, preclude theexistence of additional identical elements.

The use of the term “about” applies to all numeric values, whether ornot explicitly indicated. This term generally refers to a range ofnumbers that one of ordinary skill in the art would consider as areasonable amount of deviation to the recited numeric values (i.e.,having the equivalent function or result). For example, this term can beconstrued as including a deviation of ±10 percent of the given numericvalue provided such a deviation does not alter the end function orresult of the value. Therefore, a value of about 1% can be construed tobe a range from 0.9% to 1.1%. Furthermore, a range may be construed toinclude the start and the end of the range. For example, a range of 10%to 20% (i.e., range of 10%-20%) can includes 10% and also includes 20%,and includes percentages in between 10% and 20%, unless explicitlystated otherwise herein.

It is understood that when combinations, subsets, groups, etc. ofelements are disclosed (e.g., combinations of components in acomposition, or combinations of steps in a method), that while specificreference of each of the various individual and collective combinationsand permutations of these elements may not be explicitly disclosed, eachis specifically contemplated and described herein. By way of example, ifan item is described herein as including a component of type A, acomponent of type B, a component of type C, or any combination thereof,it is understood that this phrase describes all of the variousindividual and collective combinations and permutations of thesecomponents. For example, in some embodiments, the item described by thisphrase could include only a component of type A. In some embodiments,the item described by this phrase could include only a component of typeB. In some embodiments, the item described by this phrase could includeonly a component of type C. In some embodiments, the item described bythis phrase could include a component of type A and a component of typeB. In some embodiments, the item described by this phrase could includea component of type A and a component of type C. In some embodiments,the item described by this phrase could include a component of type Band a component of type C. In some embodiments, the item described bythis phrase could include a component of type A, a component of type B,and a component of type C. In some embodiments, the item described bythis phrase could include two or more components of type A (e.g., A1 andA2). In some embodiments, the item described by this phrase couldinclude two or more components of type B (e.g., B1 and B2). In someembodiments, the item described by this phrase could include two or morecomponents of type C (e.g., C1 and C2). In some embodiments, the itemdescribed by this phrase could include two or more of a first component(e.g., two or more components of type A (A1 and A2)), optionally one ormore of a second component (e.g., optionally one or more components oftype B), and optionally one or more of a third component (e.g.,optionally one or more components of type C). In some embodiments, theitem described by this phrase could include two or more of a firstcomponent (e.g., two or more components of type B (B1 and B2)),optionally one or more of a second component (e.g., optionally one ormore components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type C). In someembodiments, the item described by this phrase could include two or moreof a first component (e.g., two or more components of type C (C1 andC2)), optionally one or more of a second component (e.g., optionally oneor more components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type B).

“Hydrocarbon-bearing formation” or simply “formation” refers to the rockmatrix in which a wellbore may be drilled. For example, a formationrefers to a body of rock that is sufficiently distinctive and continuoussuch that it can be mapped. It should be appreciated that while the term“formation” generally refers to geologic formations of interest, thatthe term “formation,” as used herein, may, in some instances, includeany geologic points or volumes of interest (such as a survey area).

“Unconventional formation” is a subterranean hydrocarbon-bearingformation that requires intervention in order to recover hydrocarbonsfrom the reservoir at economic flow rates or volumes. For example, anunconventional formation includes reservoirs having an unconventionalmicrostructure, such as having submicron pore size (a rock matrix withan average pore size less than 1 micrometer), in which fractures areused to recover hydrocarbons from the reservoir at sufficient flow ratesor volumes (e.g., an unconventional reservoir must be fractured underpressure or have naturally occurring fractures in order to recoverhydrocarbons from the reservoir at sufficient flow rates or volumes).

In some embodiments, the unconventional formation can include areservoir having a permeability of less than 25 millidarcy (mD) (e.g.,20 mD or less, 15 mD or less, 10 mD or less, 5 mD or less, 1 mD or less,0.5 mD or less, 0.1 mD or less, 0.05 mD or less, 0.01 mD or less, 0.005mD or less, or 0.001 mD or less). In some embodiments, theunconventional formation can include a reservoir having a permeabilityof at least 0.001 mD (e.g., at least 0.005 mD, at least 0.01 mD, atleast 0.05 mD, at least 0.1 mD, at least 0.5 mD, at least 1 mD, at least5 mD, at least 10 mD, at least 15 mD, or at least 20 mD).

The unconventional formation can include a reservoir having apermeability ranging from any of the minimum values described above toany of the maximum values described above. For example, in someembodiments, the unconventional formation can include a reservoir havinga permeability of from 0.001 mD to 25 mD (e.g., from 0.001 mD to 10 mD,from 0.01 mD to 10 mD, from 0.1 mD to 10 mD, from 0.001 mD to 5 mD, from0.01 mD to 5 mD, or from 0.1 mD to 5 mD).

The formation may include faults, fractures (e.g., naturally occurringfractures, fractures created through hydraulic fracturing, etc.),geobodies, overburdens, underburdens, horizons, salts, salt welds, etc.The formation may be onshore, offshore (e.g., shallow water, deep water,etc.), etc. Furthermore, the formation may include hydrocarbons, such asliquid hydrocarbons (also known as oil or petroleum), gas hydrocarbons,a combination of liquid hydrocarbons and gas hydrocarbons (e.g.including gas condensate), etc.

The formation, the hydrocarbons, or both may also includenon-hydrocarbon items, such as pore space, connate water, brine, fluidsfrom enhanced oil recovery, etc. The formation may also be divided upinto one or more hydrocarbon zones, and hydrocarbons can be producedfrom each desired hydrocarbon zone.

The term formation may be used synonymously with the term reservoir. Forexample, in some embodiments, the reservoir may be, but is not limitedto, a shale reservoir, a carbonate reservoir, a tight sandstonereservoir, a tight siltstone reservoir, a gas hydrate reservoir, acoalbed methane reservoir, etc. Indeed, the terms “formation,”“reservoir,” “hydrocarbon,” and the like are not limited to anydescription or configuration described herein.

“Wellbore” refers to a continuous hole for use in hydrocarbon recovery,including any openhole or uncased portion of the wellbore. For example,a wellbore may be a cylindrical hole drilled into the formation suchthat the wellbore is surrounded by the formation, including rocks,sands, sediments, etc. A wellbore may be used for injection. A wellboremay be used for production. A wellbore may be used for hydraulicfracturing of the formation. A wellbore even may be used for multiplepurposes, such as injection and production. The wellbore may havevertical, inclined, horizontal, or a combination of trajectories. Forexample, the wellbore may be a vertical wellbore, a horizontal wellbore,a multilateral wellbore, or slanted wellbore. The wellbore may include a“build section.” “Build section” refers to practically any section of awellbore where the deviation is changing. As an example, the deviationis changing when the wellbore is curving. The wellbore may include aplurality of components, such as, but not limited to, a casing, a liner,a tubing string, a heating element, a sensor, a packer, a screen, agravel pack, etc. The wellbore may also include equipment to controlfluid flow into the wellbore, control fluid flow out of the wellbore, orany combination thereof. For example, each wellbore may include awellhead, a BOP, chokes, valves, or other control devices. These controldevices may be located on the surface, under the surface (e.g., downholein the wellbore), or any combination thereof. The wellbore may alsoinclude at least one artificial lift device, such as, but not limitedto, an electrical submersible pump (ESP) or gas lift. Some non-limitingexamples of wellbores may be found in U.S. Patent ApplicationPublication No. 2014/0288909 (Attorney Dkt. No. T-9407) and U.S. PatentApplication Publication No. 2016/0281494A1 (Attorney Dkt. No. T-10089),each of which is incorporated by reference in its entirety. The termwellbore is not limited to any description or configuration describedherein. The term wellbore may be used synonymously with the termsborehole or well.

“Single-phase liquid or fluid,” as used herein, refers to a fluid whichonly has a single-phase, i.e. only a water phase. A single-phase fluidis not an emulsion. A single-phase fluid is in a thermodynamicallystable state such that it does not macroscopically separate intodistinct layers or precipitate out solid particles. In some embodiments,the single-phase liquid comprises a single-phase liquid surfactantpackage including one or more anionic and/or non-ionic surfactants.

“Aqueous stable,” as used herein, refers to a solution whose solublecomponents remain dissolved and is a single phase as opposed toprecipitating as particulates or phase separating into 2 or more phases.As such, aqueous stable solutions are clear and transparent staticallyand when agitated. Conversely, solutions may be described as “aqueousunstable” when components precipitate from solution as particulates orphase separates into 2 or more phases. The aqueous stability ofsolutions can be assessed by evaluating whether the Tyndall Effect(light scattering by suspended particulates) is observed whenmonochromatic light is directed through the solution. If a sampleexhibits the Tyndall effect, the solution may be characterized as“aqueous unstable.” Conversely, if a sample does not exhibit the Tyndalleffect, the solution may be characterized as “aqueous stable.”

“Slickwater,” as used herein, refers to water-based injection fluidcomprising a friction reducer which is typically pumped at high rates tofracture a reservoir. Optionally when employing slickwater, smallersized proppant particles (e.g., 40/70 or 50/140 mesh size) are used dueto the fluid having a relatively low viscosity (and therefore adiminished ability to transport sizable proppants relative to moreviscous fluids). In some embodiments, proppants are added to some stagesof completion/stimulation during production of an unconventionalreservoir. In some embodiments, slickwater is injected with a smallquantity of proppant.

“Friction reducer,” as used herein, refers to a chemical additive thatalters fluid rheological properties to reduce friction created withinthe fluid as it flows through small-diameter tubulars or similarrestrictions (e.g., valves, pumps). Generally polymers, or similarfriction reducing agents, add viscosity to the fluid, which reduces theturbulence induced as the fluid flows. Reductions in fluid friction ofgreater than 50% are possible depending on the friction reducerutilized, which allows the injection fluid to be injected into awellbore at a much higher injection rate (e.g., between 60 to 100barrels per minute) and also lower pumping pressure during proppantinjection.

“Injection fluid” or “LPS injection fluid,” as used herein, refers toany fluid which is injected into a reservoir via a well. The injectionfluid may include one or more of an acid, a polymer, a friction reducer,a gelling agent, a crosslinker, a scale inhibitor, a breaker, a pHadjusting agent, a non-emulsifier agent, an iron control agent, acorrosion inhibitor, a biocide, a clay stabilizing agent, a proppant, awettability alteration chemical, a co-solvent (e.g., a C1-C5 alcohol, oran alkoxylated C1-C5 alcohol), or any combination thereof, to increasethe efficacy of the injection fluid.

“Low particle size injection fluid” refers to an injection fluid havinga maximum particle size of less than 0.1 micrometers in diameter inparticle size distribution measurements performed at a temperature andsalinity of the unconventional formation for which injection is tooccur. For example, the low particle size injection fluid can be formedby mixing an aqueous-based injection fluid with a single-phase fluidcomprising a single-phase liquid surfactant package. Prior to beingdosed with the anionic or non-ionic surfactant to form the low particlesize injection fluid, the aqueous based fluid may have been used as theinjection fluid.

“Fracturing fluid,” as used herein, refers to an injection fluid that isinjected into the well under pressure in order to cause fracturingwithin a portion of the reservoir.

The term “interfacial tension” or “IFT” as used herein refers to thesurface tension between test oil and water of different salinitiescontaining a surfactant formulation at different concentrations.Typically, interfacial tensions are measured using a spinning droptensiometer or calculated from phase behavior experiments.

The term “proximate” is defined as “near”. If item A is proximate toitem B, then item A is near item B. For example, in some embodiments,item A may be in contact with item B. For example, in some embodiments,there may be at least one barrier between item A and item B such thatitem A and item B are near each other, but not in contact with eachother. The barrier may be a fluid barrier, a non-fluid barrier (e.g., astructural barrier), or any combination thereof. Both scenarios arecontemplated within the meaning of the term “proximate.”

Unless defined otherwise, all technical and scientific terms used hereinhave the same meanings as commonly understood by one of skill in the artto which the disclosed invention belongs. Unless otherwise specified,all percentages are in weight percent and the pressure is inatmospheres.

The compositions and methods described herein relate to compositions andmethods described in PCT/______, filed Jul. 31, 2018 (Attorney DocketNo. 10467-028WO1 (CVX Ref: T-10666B), filed Jul. 31, 2018 entitled“Injection Fluids Comprising Non-Ionic Surfactants for TreatingUnconventional Formations”); and PCT/______, filed Jul. 31, 2018(Attorney Docket No. 10467-030WO1 (CVX Ref: T-10666C), filed Jul. 31,2018 entitled “Injection Fluids for Stimulating Fractured Formations”),all of which are hereby incorporated by reference.

Compositions

An embodiment of the disclosure is a single-phase liquid surfactantpackage which decreases the particle size distribution when combinedwith an aqueous-based injection fluid to create a low particle size(LPS) injection fluid. The low particle size injection fluid can have amaximum particle size of less than 0.1 micrometers in diameter inparticle size distribution measurements performed at a temperature andsalinity of the unconventional subterranean formation. In specificembodiments, after injection into a reservoir, the LPS injection fluidretains the lowered particle size distribution within the reservoir. Incertain embodiments, the LPS injection fluid lowers the particle sizedistribution of the reservoir fluid after being injected into thereservoir and mixing with the reservoir fluid. In embodiments, theaqueous-based injection fluid when combined with the single-phase liquidsurfactant package maintains itself as a single-phase, that is, as theLPS injection fluid is pumped downhole it remains a homogenoussingle-phase solution within the reservoir, even when mixed with thenative reservoir fluid.

The single-phase liquid surfactant package can comprise a primarysurfactant and optionally one or more secondary surfactants. The primarysurfactant can comprise an anionic surfactant. The one or more secondarysurfactants can comprise one or more non-ionic surfactants, one or moreadditional anionic surfactants, one or more cationic surfactants, one ormore zwitterionic surfactants, or any combination thereof.

In some embodiments, the primary surfactant can comprise at least 10% byweight (e.g., at least 15% by weight, at least 20% by weight, at least25% by weight, at least 30% by weight, at least 35% by weight, at least40% by weight, at least 45% by weight, at least 50% by weight, at least55% by weight, at least 60% by weight, at least 65% by weight, at least70% by weight, at least 75% by weight, at least 80% by weight, or atleast 85% by weight) of the single-phase liquid surfactant package,based on the total weight of the single-phase liquid surfactant package.In some embodiments, the primary surfactant can comprise 90% by weightor less (e.g., 85% by weight or less, 80% by weight or less, 75% byweight or less, 70% by weight or less, 65% by weight or less, 60% byweight or less, 55% by weight or less, 50% by weight or less, 45% byweight or less, 40% by weight or less, 35% by weight or less, 30% byweight or less, 25% by weight or less, 20% by weight or less, or 15% byweight or less) of the single-phase liquid surfactant package, based onthe total weight of the single-phase liquid surfactant package.

The primary surfactant can be present in the single-phase liquidsurfactant package in an amount ranging from any of the minimum valuesdescribed above to any of the maximum values described above. Forexample, in some embodiments, the primary surfactant can comprise from10% to 90% by weight (e.g., from 10% to 50% by weight) of thesingle-phase liquid surfactant package, based on the total weight of thesingle-phase liquid surfactant package.

In some embodiments, the one or more secondary surfactants can compriseat least 10% by weight (e.g., at least 15% by weight, at least 20% byweight, at least 25% by weight, at least 30% by weight, at least 35% byweight, at least 40% by weight, at least 45% by weight, at least 50% byweight, at least 55% by weight, at least 60% by weight, at least 65% byweight, at least 70% by weight, at least 75% by weight, at least 80% byweight, or at least 85% by weight) of the single-phase liquid surfactantpackage, based on the total weight of the single-phase liquid surfactantpackage. In some embodiments, the one or more secondary surfactants cancomprise 90% by weight or less (e.g., 85% by weight or less, 80% byweight or less, 75% by weight or less, 70% by weight or less, 65% byweight or less, 60% by weight or less, 55% by weight or less, 50% byweight or less, 45% by weight or less, 40% by weight or less, 35% byweight or less, 30% by weight or less, 25% by weight or less, 20% byweight or less, or 15% by weight or less) of the single-phase liquidsurfactant package, based on the total weight of the single-phase liquidsurfactant package.

The one or more secondary surfactants can be present in the single-phaseliquid surfactant package in an amount ranging from any of the minimumvalues described above to any of the maximum values described above. Forexample, in some embodiments, the one or more secondary surfactants cancomprise from 10% to 90% by weight (e.g., from 10% to 50% by weight) ofthe single-phase liquid surfactant package, based on the total weight ofthe single-phase liquid surfactant package.

In some embodiments, the single-phase liquid surfactant package cancomprise an anionic surfactant. In other embodiments, the single-phaseliquid surfactant package can consist essentially of an anionicsurfactant (i.e., the anionic surfactant is the only surfactant presentin the single-phase liquid surfactant package). In other embodiments,the single-phase liquid surfactant package can consist of an anionicsurfactant. In some of these embodiments, the single-phase liquidsurfactant package further includes water. In some of these embodiments,the single-phase liquid surfactant package does not comprise ahydrocarbon.

In some embodiments, the single-phase liquid surfactant package cancomprise an anionic surfactant and a non-ionic surfactant. In otherembodiments, the single-phase liquid surfactant package can consistessentially of an anionic surfactant and a non-ionic surfactant (i.e.,the anionic surfactant and the non-ionic surfactant are the onlysurfactants present in the single-phase liquid surfactant package). Inother embodiments, the single-phase liquid surfactant package canconsist of an anionic surfactant and a non-ionic surfactant. In some ofthese embodiments, the single-phase liquid surfactant package furtherincludes water. In some of these embodiments, the single-phase liquidsurfactant package does not comprise a hydrocarbon.

In some embodiments, the single-phase liquid surfactant package cancomprise an anionic surfactant, a second anionic surfactant, and anon-ionic surfactant. In other embodiments, the single-phase liquidsurfactant package can consist essentially of an anionic surfactant, asecond anionic surfactant, and a non-ionic surfactant (i.e., the anionicsurfactant, the second anionic surfactant, and the non-ionic surfactantare the only surfactants present in the single-phase liquid surfactantpackage). In other embodiments, the single-phase liquid surfactantpackage can consist of an anionic surfactant, a second anionicsurfactant, and a non-ionic surfactant. In some of these embodiments,the single-phase liquid surfactant package further includes water. Insome of these embodiments, the single-phase liquid surfactant packagedoes not comprise a hydrocarbon.

Suitable anionic surfactants for use as a primary surfactant and/or asecondary surfactant include a hydrophobic tail that comprises from 6 to60 carbon atoms. In some embodiments, the anionic surfactant can includea hydrophobic tail that comprises at least 6 carbon atoms (e.g., atleast 7 carbon atoms, at least 8 carbon atoms, at least 9 carbon atoms,at least 10 carbon atoms, at least 11 carbon atoms, at least 12 carbonatoms, at least 13 carbon atoms, at least 14 carbon atoms, at least 15carbon atoms, at least 16 carbon atoms, at least 17 carbon atoms, atleast 18 carbon atoms, at least 19 carbon atoms, at least 20 carbonatoms, at least 21 carbon atoms, at least 22 carbon atoms, at least 23carbon atoms, at least 24 carbon atoms, at least 25 carbon atoms, atleast 26 carbon atoms, at least 27 carbon atoms, at least 28 carbonatoms, at least 29 carbon atoms, at least 30 carbon atoms, at least 31carbon atoms, at least 32 carbon atoms, at least 33 carbon atoms, atleast 34 carbon atoms, at least 35 carbon atoms, at least 36 carbonatoms, at least 37 carbon atoms, at least 38 carbon atoms, at least 39carbon atoms, at least 40 carbon atoms, at least 41 carbon atoms, atleast 42 carbon atoms, at least 43 carbon atoms, at least 44 carbonatoms, at least 45 carbon atoms, at least 46 carbon atoms, at least 47carbon atoms, at least 48 carbon atoms, at least 49 carbon atoms, atleast 50 carbon atoms, at least 51 carbon atoms, at least 52 carbonatoms, at least 53 carbon atoms, at least 54 carbon atoms, at least 55carbon atoms, at least 56 carbon atoms, at least 57 carbon atoms, atleast 58 carbon atoms, or at least 59 carbon atoms). In someembodiments, the anionic surfactant can include a hydrophobic tail thatcomprises 60 carbon atoms or less (e.g., 59 carbon atoms or less, 58carbon atoms or less, 57 carbon atoms or less, 56 carbon atoms or less,55 carbon atoms or less, 54 carbon atoms or less, 53 carbon atoms orless, 52 carbon atoms or less, 51 carbon atoms or less, 50 carbon atomsor less, 49 carbon atoms or less, 48 carbon atoms or less, 47 carbonatoms or less, 46 carbon atoms or less, 45 carbon atoms or less, 44carbon atoms or less, 43 carbon atoms or less, 42 carbon atoms or less,41 carbon atoms or less, 40 carbon atoms or less, 39 carbon atoms orless, 38 carbon atoms or less, 37 carbon atoms or less, 36 carbon atomsor less, 35 carbon atoms or less, 34 carbon atoms or less, 33 carbonatoms or less, 32 carbon atoms or less, 31 carbon atoms or less, 30carbon atoms or less, 29 carbon atoms or less, 28 carbon atoms or less,27 carbon atoms or less, 26 carbon atoms or less, 25 carbon atoms orless, 24 carbon atoms or less, 23 carbon atoms or less, 22 carbon atomsor less, 21 carbon atoms or less, 20 carbon atoms or less, 19 carbonatoms or less, 18 carbon atoms or less, 17 carbon atoms or less, 16carbon atoms or less, 15 carbon atoms or less, 14 carbon atoms or less,13 carbon atoms or less, 12 carbon atoms or less, 11 carbon atoms orless, 10 carbon atoms or less, 9 carbon atoms or less, 8 carbon atoms orless, or 7 carbon atoms or less).

The anionic surfactant can include a hydrophobic tail that comprises anumber of carbon atoms ranging from any of the minimum values describedabove to any of the maximum values described above. For example, in someembodiments, the anionic surfactant can comprise a hydrophobic tailcomprising from 6 to 15, from 16 to 30, from 31 to 45, from 46 to 60,from 6 to 25, from 26 to 60, from 6 to 30, from 31 to 60, from 6 to 32,from 33 to 60, from 6 to 12, from 13 to 22, from 23 to 32, from 33 to42, from 43 to 52, from 53 to 60, from 6 to 10, from 10 to 15, from 16to 25, from 26 to 35, or from 36 to 45 carbon atoms. The hydrophobic(lipophilic) carbon tail may be a straight chain, branched chain, and/ormay comprise cyclic structures. The hydrophobic carbon tail may comprisesingle bonds, double bonds, triple bonds, or any combination thereof. Insome embodiments, the anionic surfactant can include a branchedhydrophobic tail derived from Guerbet alcohols. The hydrophilic portionof the anionic surfactant can comprise, for example, one or more sulfatemoieties (e.g., one, two, or three sulfate moieties), one or moresulfonate moieties (e.g., one, two, or three sulfonate moieties), one ormore sulfosuccinate moieties (e.g., one, two, or three sulfosuccinatemoieties), one or more carboxylate moieties (e.g., one, two, or threecarboxylate moieties), or any combination thereof.

In some embodiments, the anionic surfactant can comprise, for example asulfonate, a disulfonate, a polysulfonate, a sulfate, a disulfate, apolysulfate, a sulfosuccinate, a disulfosuccinate, a polysulfosuccinate,a carboxylate, a dicarboxylate, a polycarboxylate, or any combinationthereof. In some examples, the anionic surfactant can comprise aninternal olefin sulfonate (IOS), an isomerized olefin sulfonate, an alfaolefin sulfonate (AOS), an alkyl aryl sulfonate (AAS), a xylenesulfonate, an alkane sulfonate, a petroleum sulfonate, an alkyl diphenyloxide (di)sulfonate, an alcohol sulfate, an alkoxy sulfate, an alkoxysulfonate, an alkoxy carboxylate, an alcohol phosphate, or an alkoxyphosphate. In some embodiments, the anionic surfactant can comprise analkoxy carboxylate surfactant, an alkoxy sulfate surfactant, an alkoxysulfonate surfactant, an alkyl sulfonate surfactant, an aryl sulfonatesurfactant, or an olefin sulfonate surfactant.

An “alkoxy carboxylate surfactant” or “alkoxy carboxylate” refers to acompound having an alkyl or aryl attached to one or more alkoxylenegroups (typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—)which, in turn is attached to —COO⁻ or acid or salt thereof includingmetal cations such as sodium. In embodiments, the alkoxy carboxylatesurfactant can be defined by the formulae below:

wherein R¹ is substituted or unsubstituted C6-C36 alkyl or substitutedor unsubstituted aryl; R² is, independently for each occurrence withinthe compound, hydrogen or unsubstituted C1-C6 alkyl; R³ is independentlyhydrogen or unsubstituted C1-C6 alkyl, n is an integer from 0 to 175, zis an integer from 1 to 6 and M⁺ is a monovalent, divalent or trivalentcation. In some of these embodiments, R¹ can be an unsubstituted linearor branched C6-C36 alkyl.

In certain embodiments, the alkoxy carboxylate can be aC6-C32:PO(0-65):EO(0-100)-carboxylate (i.e., a C6-C32 hydrophobic tail,such as a branched or unbranched C6-C32 alkyl group, attached to from 0to 65 propyleneoxy groups (—CH₂—CH(methyl)-O— linkers), attached in turnto from 0 to 100 ethyleneoxy groups (—CH₂—CH₂—O— linkers), attached inturn to —COO⁻ or an acid or salt thereof including metal cations such assodium). In certain embodiments, the alkoxy carboxylate can be abranched or unbranched C6-C30:PO(30-40):EO(25-35)-carboxylate. Incertain embodiments, the alkoxy carboxylate can be a branched orunbranched C6-C12:PO(30-40):EO(25-35)-carboxylate. In certainembodiments, the alkoxy carboxylate can be a branched or unbranchedC6-C30:EO(8-30)-carboxylate.

An “alkoxy sulfate surfactant” or “alkoxy sulfate” refers to asurfactant having an alkyl or aryl attached to one or more alkoxylenegroups (typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—)which, in turn is attached to —SO₃ ⁻ or acid or salt thereof includingmetal cations such as sodium. In some embodiment, the alkoxy sulfatesurfactant has the formula R—(BO)_(e)—(PO)_(f)—(EO)_(g)—SO₃ ⁻ or acid orsalt (including metal cations such as sodium) thereof, wherein R isC6-C32 alkyl, BO is —CH₂—CH(ethyl)-O—, PO is —CH₂—CH(methyl)-O—, and EOis —CH₂—CH₂—O—. The symbols e, f and g are integers from 0 to 50 whereinat least one is not zero.

In embodiments, the alkoxy sulfate surfactant can be an aryl alkoxysulfate surfactant. The aryl alkoxy surfactant can be an alkoxysurfactant having an aryl attached to one or more alkoxylene groups(typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—) which,in turn is attached to —SO₃ ⁻ or acid or salt thereof including metalcations such as sodium.

An “alkyl sulfonate surfactant” or “alkyl sulfonate” refers to acompound that includes an alkyl group (e.g., a branched or unbranchedC6-C32 alkyl group) attached to —SO₃ ⁻ or acid or salt thereof includingmetal cations such as sodium.

An “aryl sulfate surfactant” or “aryl sulfate” refers to a compoundhaving an aryl group attached to —O—SO₃ ⁻ or acid or salt thereofincluding metal cations such as sodium. An “aryl sulfonate surfactant”or “aryl sulfonate” refers to a compound having an aryl group attachedto —SO₃ ⁻ or acid or salt thereof including metal cations such assodium. In some cases, the aryl group can be substituted, for example,with an alkyl group (an alkyl aryl sulfonate).

An “internal olefin sulfonate,” “isomerized olefin sulfonate,” or “IOS”refers to an unsaturated hydrocarbon compound comprising at least onecarbon-carbon double bond and at least one SO₃ ⁻ group, or a saltthereof. As used herein, a “C20-C28 internal olefin sulfonate,” “aC20-C28 isomerized olefin sulfonate,” or “C20-C28 IOS” refers to an IOS,or a mixture of IOSs with an average carbon number of 20 to 28, or of 23to 25. The C20-C28 IOS may comprise at least 80% of IOS with carbonnumbers of 20 to 28, at least 90% of IOS with carbon numbers of 20 to28, or at least 99% of IOS with carbon numbers of 20 to 28. As usedherein, a “C15-C18 internal olefin sulfonate,” “C15-C18 isomerizedolefin sulfonate,” or “C15-C18 IOS” refers to an IOS or a mixture ofIOSs with an average carbon number of 15 to 18, or of 16 to 17. TheC15-C18 IOS may comprise at least 80% of IOS with carbon numbers of 15to 18, at least 90% of IOS with carbon numbers of 15 to 18, or at least99% of IOS with carbon numbers of 15 to 18. The internal olefinsulfonates or isomerized olefin sulfonates may be alpha olefinsulfonates, such as an isomerized alpha olefin sulfonate. The internalolefin sulfonates or isomerized olefin sulfonates may also comprisebranching. In certain embodiments, C15-18 IOS may be added to thesingle-phase liquid surfactant package when the LPS injection fluid isintended for use in high temperature unconventional subterraneanformations, such as formations above 130° F. (approximately 55° C.). TheIOS may be at least 20% branching, 30% branching, 40% branching, 50%branching, 60% branching, or 65% branching. In some embodiments, thebranching is between 20-98%, 30-90%, 40-80%, or around 65%. Examples ofinternal olefin sulfonates and the methods to make them are found inU.S. Pat. No. 5,488,148, U.S. Patent Application Publication2009/0112014, and SPE 129766, all incorporated herein by reference.

In embodiments, the anionic surfactant can be a disulfonate,alkyldiphenyloxide disulfonate, mono alkyldiphenyloxide disulfonate, dialkyldiphenyloxide disulfonate, or a di alkyldiphenyloxidemonosulfonate, where the alkyl group can be a C6-C36 linear or branchedalkyl group. In embodiments, the anionic surfactant can be analkylbenzene sulfonate or a dibenzene disufonate. In embodiments, theanionic surfactant can be benzenesulfonic acid,decyl(sulfophenoxy)-disodium salt; linear or branched C6-C36alkyl:PO(0-65):EO(0-100) sulfate; or linear or branched C6-C36alkyl:PO(0-65):EO(0-100) carboxylate. In embodiments, the anionicsurfactant is an isomerized olefin sulfonate (C6-C30), internal olefinsulfonate (C6-C30) or internal olefin disulfonate (C6-C30). In someembodiments, the anionic surfactant is a Guerbet-PO(0-65)-EO(0-100)sulfate (Guerbet portion can be C6-C36). In some embodiments, theanionic surfactant is a Guerbet-PO(0-65)-EO(0-100) carboxylate (Guerbetportion can be C6-C36). In some embodiments, the anionic surfactant isalkyl PO(0-65) and EO(0-100) sulfonate: where the alkyl group is linearor branched C6-C36. In some embodiments, the anionic surfactant is asulfosuccinate, such as a dialkylsulfosuccinate. In some embodiments,the anionic surfactant is an alkyl aryl sulfonate (AAS) (e.g. an alkylbenzene sulfonate (ABS)), a C10-C30 internal olefin sulfate (IOS), apetroleum sulfonate, or an alkyl diphenyl oxide (di)sulfonate.

In some examples, the anionic surfactant can comprise a surfactantdefined by the formula below:

R¹—R²—R³

wherein R¹ comprises a branched or unbranched, saturated or unsaturated,cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atomsand an oxygen atom linking R¹ and R²; R² comprises an alkoxylated chaincomprising at least one oxide group selected from the group consistingof ethylene oxide, propylene oxide, butylene oxide, and combinationsthereof; and R³ comprises a branched or unbranched hydrocarbon chaincomprising 2-12 carbon atoms and from 2 to 5 carboxylate groups.

In some examples, the anionic surfactant can comprise a surfactantdefined by the formula below:

wherein R⁴ is a branched or unbranched, saturated or unsaturated, cyclicor non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms; and Mrepresents a counterion (e.g., Na⁺, K⁺). In some embodiments, R⁴ is abranched or unbranched, saturated or unsaturated, cyclic or non-cyclic,hydrophobic carbon chain having 6-16 carbon atoms.

Suitable non-ionic surfactants for use as a secondary surfactant includecompounds that can be added to increase wettability. In embodiments, thehydrophilic-lipophilic balance (HLB) of the non-ionic surfactant isgreater than 10 (e.g., greater than 9, greater than 8, or greater than7). In some embodiments, the HLB of the non-ionic surfactant is from 7to 10.

The non-ionic surfactant can comprise a hydrophobic tail comprising from6 to 60 carbon atoms. In some embodiments, the non-ionic surfactant caninclude a hydrophobic tail that comprises at least 6 carbon atoms (e.g.,at least 7 carbon atoms, at least 8 carbon atoms, at least 9 carbonatoms, at least 10 carbon atoms, at least 11 carbon atoms, at least 12carbon atoms, at least 13 carbon atoms, at least 14 carbon atoms, atleast 15 carbon atoms, at least 16 carbon atoms, at least 17 carbonatoms, at least 18 carbon atoms, at least 19 carbon atoms, at least 20carbon atoms, at least 21 carbon atoms, at least 22 carbon atoms, atleast 23 carbon atoms, at least 24 carbon atoms, at least 25 carbonatoms, at least 26 carbon atoms, at least 27 carbon atoms, at least 28carbon atoms, at least 29 carbon atoms, at least 30 carbon atoms, atleast 31 carbon atoms, at least 32 carbon atoms, at least 33 carbonatoms, at least 34 carbon atoms, at least 35 carbon atoms, at least 36carbon atoms, at least 37 carbon atoms, at least 38 carbon atoms, atleast 39 carbon atoms, at least 40 carbon atoms, at least 41 carbonatoms, at least 42 carbon atoms, at least 43 carbon atoms, at least 44carbon atoms, at least 45 carbon atoms, at least 46 carbon atoms, atleast 47 carbon atoms, at least 48 carbon atoms, at least 49 carbonatoms, at least 50 carbon atoms, at least 51 carbon atoms, at least 52carbon atoms, at least 53 carbon atoms, at least 54 carbon atoms, atleast 55 carbon atoms, at least 56 carbon atoms, at least 57 carbonatoms, at least 58 carbon atoms, or at least 59 carbon atoms). In someembodiments, the non-ionic surfactant can include a hydrophobic tailthat comprises 60 carbon atoms or less (e.g., 59 carbon atoms or less,58 carbon atoms or less, 57 carbon atoms or less, 56 carbon atoms orless, 55 carbon atoms or less, 54 carbon atoms or less, 53 carbon atomsor less, 52 carbon atoms or less, 51 carbon atoms or less, 50 carbonatoms or less, 49 carbon atoms or less, 48 carbon atoms or less, 47carbon atoms or less, 46 carbon atoms or less, 45 carbon atoms or less,44 carbon atoms or less, 43 carbon atoms or less, 42 carbon atoms orless, 41 carbon atoms or less, 40 carbon atoms or less, 39 carbon atomsor less, 38 carbon atoms or less, 37 carbon atoms or less, 36 carbonatoms or less, 35 carbon atoms or less, 34 carbon atoms or less, 33carbon atoms or less, 32 carbon atoms or less, 31 carbon atoms or less,30 carbon atoms or less, 29 carbon atoms or less, 28 carbon atoms orless, 27 carbon atoms or less, 26 carbon atoms or less, 25 carbon atomsor less, 24 carbon atoms or less, 23 carbon atoms or less, 22 carbonatoms or less, 21 carbon atoms or less, 20 carbon atoms or less, 19carbon atoms or less, 18 carbon atoms or less, 17 carbon atoms or less,16 carbon atoms or less, 15 carbon atoms or less, 14 carbon atoms orless, 13 carbon atoms or less, 12 carbon atoms or less, 11 carbon atomsor less, 10 carbon atoms or less, 9 carbon atoms or less, 8 carbon atomsor less, or 7 carbon atoms or less).

The non-ionic surfactant can include a hydrophobic tail that comprises anumber of carbon atoms ranging from any of the minimum values describedabove to any of the maximum values described above. For example, in someembodiments, the non-ionic surfactant can comprise a hydrophobic tailcomprising from 6 to 15, from 16 to 30, from 31 to 45, from 46 to 60,from 6 to 25, from 26 to 60, from 6 to 30, from 31 to 60, from 6 to 32,from 33 to 60, from 6 to 12, from 13 to 22, from 23 to 32, from 33 to42, from 43 to 52, from 53 to 60, from 6 to 10, from 10 to 15, from 16to 25, from 26 to 35, or from 36 to 45 carbon atoms. In some cases, thehydrophobic tail may be a straight chain, branched chain, and/or maycomprise cyclic structures. The hydrophobic carbon tail may comprisesingle bonds, double bonds, triple bonds, or any combination thereof. Insome cases, the hydrophobic tail can comprise an alkyl group, with orwithout an aromatic ring (e.g., a phenyl ring) attached to it. In someembodiments, the hydrophobic tail can comprise a branched hydrophobictail derived from Guerbet alcohols.

Example non-ionic surfactants include alkyl aryl alkoxy alcohols, alkylalkoxy alcohols, or any combination thereof. In embodiments, thenon-ionic surfactant may be a mix of surfactants with different lengthlipophilic tail chain lengths. For example, the non-ionic surfactant maybe C9-C11:9E0, which indicates a mixture of non-ionic surfactants thathave a lipophilic tail length of 9 carbon to 11 carbon, which isfollowed by a chain of 9 EOs. The hydrophilic moiety is an alkyleneoxychain (e.g., an ethoxy (EO), butoxy (BO) and/or propoxy (PO) chain withtwo or more repeating units of EO, BO, and/or PO). In some embodiments,1-100 repeating units of EO are present. In some embodiments, 0-65repeating units of PO are present. In some embodiments, 0-25 repeatingunits of BO are present. For example, the non-ionic surfactant couldcomprise 10E0:5PO or 5EO. In embodiments, the non-ionic surfactant maybe a mix of surfactants with different length lipophilic tail chainlengths. For example, the non-ionic surfactant may be C9-C11:PO9:EO2,which indicates a mixture of non-ionic surfactants that have alipophilic tail length of 9 carbon to 11 carbon, which is followed by achain of 9 POs and 2 EOs. In specific embodiments, the non-ionicsurfactant is linear C9-C11:9EO. In some embodiments, the non-ionicsurfactant is a Guerbet PO(0-65) and EO(0-100) (Guerbet can be C6-C36);or alkyl PO(0-65) and EO(0-100): where the alkyl group is linear orbranched C1-C36. In some examples, the non-ionic surfactant can comprisea branched or unbranched C6-C32:PO(0-65):EO(0-100) (e.g., a branched orunbranched C6-C30:PO(30-40):EO(25-35), a branched or unbranchedC6-C12:PO(30-40):EO(25-35), a branched or unbranched C6-30:EO(8-30), orany combination thereof). In some embodiments, the non-ionic surfactantis one or more alkyl polyglucosides.

Example cationic surfactants include surfactant analogous to thosedescribed above, except bearing primary, secondary, or tertiary amines,or quaternary ammonium cations, as a hydrophilic head group.“Zwitterionic” or “zwitterion” as used herein refers to a neutralmolecule with a positive (or cationic) and a negative (or anionic)electrical charge at different locations within the same molecule.Example zwitterionic surfactants include betains and sultains.

Examples of suitable surfactants are disclosed, for example, in U.S.Pat. Nos. 3,811,504, 3,811,505, 3,811,507, 3,890,239, 4,463,806,6,022,843, 6,225,267, 7,629,299, 7,770,641, 9,976,072, 8,211, 837,9,422,469, 9,605,198, and 9,617,464; WIPO Patent Application Nos.WO/2008/079855, WO/2012/027757 and WO/2011/094442; as well as U.S.Patent Application Nos. 2005/0199395, 2006/0185845, 2006/0189486,2009/0270281, 2011/0046024, 2011/0100402, 2011/0190175, 2007/0191633,2010/004843. 2011/0201531, 2011/0190174, 2011/0071057, 2011/0059873,2011/0059872, 2011/0048721, 2010/0319920, 2010/0292110, and2017/0198202, each of which is hereby incorporated by reference hereinin its entirety for its description of example surfactants.

Optionally, the single-phase liquid surfactant package can include oneor more additional components. For example, the single-phase liquidsurfactant package can further comprise an acid, a polymer, a frictionreducer, a gelling agent, a crosslinker, a scale inhibitor, a breaker, apH adjusting agent, a non-emulsifier agent, an iron control agent, acorrosion inhibitor, a biocide, a clay stabilizing agent, a proppant, awettability alteration chemical, a co-solvent (e.g., a C1-C5 alcohol, oran alkoxylated C1-C5 alcohol), or any combination thereof.

In some embodiments, the single-phase liquid surfactant package canfurther include one or more co-solvents. Suitable co-solvents includealcohols, such as lower carbon chain alcohols such as isopropyl alcohol,ethanol, n-propyl alcohol, n-butyl alcohol, sec-butyl alcohol, n-amylalcohol, sec-amyl alcohol, n-hexyl alcohol, sec-hexyl alcohol and thelike; alcohol ethers, polyalkylene alcohol ethers, polyalkylene glycols,poly(oxyalkylene)glycols, poly(oxyalkylene)glycol ethers, ethoxylatedphenol, or any other common organic co-solvent or combinations of anytwo or more co-solvents. In one embodiment, the co-solvent can comprisealkyl ethoxylate (C1-C6)-XEO X=1-30-linear or branched. In someembodiments, the co-solvent can comprise ethylene glycol butyl ether(EGBE), diethylene glycol monobutyl ether (DGBE), triethylene glycolmonobutyl ether (TEGBE), ethylene glycol dibutyl ether (EGDE),polyethylene glycol monomethyl ether (mPEG), or any combination thereof.

Prior to injection into a well, the single-phase liquid surfactantpackage is combined with an aqueous-based injection fluid to form an LPSinjection fluid. The single-phase liquid surfactant package may be addeddirectly into the aqueous-based injection fluid, or the single-phaseliquid surfactant package may be diluted (e.g., with water or anaqueous-based injection fluid) prior to being added to the injectionfluid. In embodiments, the aqueous-based injection fluid prior toaddition of the single-phase liquid surfactant package is anaqueous-based injection fluid that was previously injected into thewell. When added, the single-phase liquid surfactant package candecrease the particle size distribution within the aqueous-basedinjection fluid, creating an LPS injection fluid.

In example embodiments, the aqueous-based injection fluid can compriseany type of water, treated or untreated, and can vary in salt content.For example, the aqueous-based injection fluid can comprise sea water,brackish water, fresh water, flowback or produced water, wastewater(e.g., reclaimed or recycled), river water, lake or pond water, aquiferwater, brine (e.g., reservoir or synthetic brine), or any combinationthereof. In some embodiments, the aqueous-based injection fluid cancomprise slickwater.

The LPS injection fluids can comprise from 30% to 99.85% by weight ofthe total composition of water, for example from 70% to 98% water.

In some embodiments, the aqueous-based injection fluid can include anacid, a polymer, a friction reducer, a gelling agent, a crosslinker, abreaker, a pH adjusting agent, a non-emulsifier agent, an iron controlagent, a scale inhibitor, a corrosion inhibitor, a biocide, a claystabilizing agent, a proppant, a wettability alteration chemical, aco-solvent (e.g., a C1-C5 alcohol, or an alkoxylated C1-C5 alcohol), orany combination thereof. In certain embodiments, the aqueous-basedinjection fluid can comprise an acid (e.g., at least 10% acid, such asfrom 10% to 20% by weight acid). In certain embodiments, the injectionfluid can comprise a proppant.

Once combined with the aqueous-based injection fluid, the primarysurfactant can have a concentration within the low particle sizeinjection fluid of at least 0.01% by weight (e.g., at least 0.02% byweight, at least 0.03% by weight, at least 0.04% by weight, at least0.05% by weight, at least 0.06% by weight, at least 0.07% by weight, atleast 0.08% by weight, at least 0.09% by weight, at least 0.1% byweight, at least 0.15% by weight, at least 0.2% by weight, at least0.25% by weight, at least 0.3% by weight, at least 0.35% by weight, atleast 0.4% by weight, at least 0.45% by weight, at least 0.5% by weight,at least 0.55% by weight, at least 0.6% by weight, at least 0.65% byweight, at least 0.7% by weight, at least 0.75% by weight, at least 0.8%by weight, at least 0.85% by weight, at least 0.9% by weight, at least0.95% by weight, at least 1% by weight, at least 1.25% by weight, atleast 1.5% by weight, at least 1.75% by weight, at least 2% by weight,or at least 2.25% by weight), based on the total weight of the lowparticle size injection fluid. In some embodiments, the primarysurfactant can have a concentration within the low particle sizeinjection fluid of 2.5% by weight or less (e.g., 2.25% by weight orless, 2% by weight or less, 1.75% by weight or less, 1.5% by weight orless, 1.25% by weight or less, 1% by weight or less, 0.95% by weight orless, 0.9% by weight or less, 0.85% by weight or less, 0.8% by weight orless, 0.75% by weight or less, 0.7% by weight or less, 0.65% by weightor less, 0.6% by weight or less, 0.55% by weight or less, 0.5% by weightor less, 0.45% by weight or less, 0.4% by weight or less, 0.35% byweight or less, 0.3% by weight or less, 0.25% by weight or less, 0.2% byweight or less, 0.15% by weight or less, 0.1% by weight or less, 0.09%by weight or less, 0.08% by weight or less, 0.07% by weight or less,0.06% by weight or less, 0.05% by weight or less, 0.04% by weight orless, 0.03% by weight or less, or 0.02% by weight or less), based on thetotal weight of the LPS injection fluid. In particular embodiments, theprimary surfactant can have a concentration within the low particle sizeinjection fluid of less than 1%, less than 0.5%, less than 0.2%, lessthan 0.1%, less than 0.075%, or less than 0.05%.

The primary surfactant can have a concentration within the low particlesize injection fluid ranging from any of the minimum values describedabove to any of the maximum values described above. For example, in someembodiments, the primary surfactant can have a concentration within thelow particle size injection fluid of from 0.01% to 2.5% by weight (e.g.,from 0.05% to 0.5% by weight), based on the total weight of the lowparticle size injection fluid.

When present, the one or more secondary surfactants can have aconcentration within the low particle size injection fluid of at least0.001% by weight (e.g., at least 0.005% by weight, at least 0.01% byweight, at least 0.02% by weight, at least 0.03% by weight, at least0.04% by weight, at least 0.05% by weight, at least 0.06% by weight, atleast 0.07% by weight, at least 0.08% by weight, at least 0.09% byweight, at least 0.1% by weight, at least 0.15% by weight, at least 0.2%by weight, at least 0.25% by weight, at least 0.3% by weight, at least0.35% by weight, at least 0.4% by weight, at least 0.45% by weight, atleast 0.5% by weight, at least 0.55% by weight, at least 0.6% by weight,at least 0.65% by weight, at least 0.7% by weight, at least 0.75% byweight, at least 0.8% by weight, at least 0.85% by weight, at least 0.9%by weight, at least 0.95% by weight, at least 1% by weight, at least1.25% by weight, at least 1.5% by weight, at least 1.75% by weight, atleast 2% by weight, or at least 2.25% by weight), based on the totalweight of the low particle size injection fluid. In some embodiments,the one or more secondary surfactants can have a concentration withinthe low particle size injection fluid of 2.5% by weight or less (e.g.,2.25% by weight or less, 2% by weight or less, 1.75% by weight or less,1.5% by weight or less, 1.25% by weight or less, 1% by weight or less,0.95% by weight or less, 0.9% by weight or less, 0.85% by weight orless, 0.8% by weight or less, 0.75% by weight or less, 0.7% by weight orless, 0.65% by weight or less, 0.6% by weight or less, 0.55% by weightor less, 0.5% by weight or less, 0.45% by weight or less, 0.4% by weightor less, 0.35% by weight or less, 0.3% by weight or less, 0.25% byweight or less, 0.2% by weight or less, 0.15% by weight or less, 0.1% byweight or less, 0.09% by weight or less, 0.08% by weight or less, 0.07%by weight or less, 0.06% by weight or less, 0.05% by weight or less,0.04% by weight or less, 0.03% by weight or less, 0.02% by weight orless, 0.01% by weight or less, or 0.005% by weight or less), based onthe total weight of the LPS injection fluid. In particular embodiments,the one or more secondary surfactants can have a concentration withinthe low particle size injection fluid of less than 2%, less than 1.5%,less than 1%, less than 0.5%, less than 0.2%, less than 0.1%, less than0.075%, less than 0.05%, or less than 0.01%.

When present, the one or more secondary surfactants can have aconcentration within the low particle size injection fluid ranging fromany of the minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the one or moresecondary surfactants can have a concentration within the low particlesize injection fluid of from 0.001% to 2.5% by weight (e.g., from 0.001%to 1.5% by weight, or from 0.05% to 0.5% by weight), based on the totalweight of the low particle size injection fluid.

In some embodiments, the primary surfactant and one or more secondarysurfactants can be present in the LPS injection fluid, the single-phaseliquid surfactant package, or both in a weight ratio of primarysurfactant to one or more secondary surfactants of at least 1:1 (e.g.,at least 2:1, at least 2.5:1, at least 3:1, at least 4:1, at least 5:1,at least 6:1, at least 7:1, at least 8:1, or at least 9:1). In someembodiments, the primary surfactant and one or more secondarysurfactants can be present in the LPS injection fluid, the single-phaseliquid surfactant package, or both in a weight ratio of primarysurfactant to one or more secondary surfactants of 10:1 or less (e.g.,9:1 or less; 8:1 or less, 7:1 or less, 6:1 or less, 5:1 or less, 4:1 orless, 3:1 or less, 2.5:1 or less, or 2:1 or less).

The primary surfactant and one or more secondary surfactants can bepresent in the LPS injection fluid, the single-phase liquid surfactantpackage, or both in a weight ratio ranging from any of the minimumvalues described above to any of the maximum values described above. Forexample, the primary surfactant and one or more secondary surfactantscan be present in the LPS injection fluid, the single-phase liquidsurfactant package, or both in a weight ratio of primary surfactant toone or more secondary surfactants of from 1:1 to 10:1 (e.g., 1:1 to5:1).

In other embodiments, the one or more secondary surfactants are absent(i.e., the primary surfactant is the only surfactant present in thesingle-phase liquid surfactant package).

In some embodiments, the total concentration of all surfactants in theLPS injection fluid (the total concentration of the primary surfactantand the one or more secondary surfactants in the LPS injection fluid)can be at least 0.01% by weight (e.g., at least 0.02% by weight, atleast 0.03% by weight, at least 0.04% by weight, at least 0.05% byweight, at least 0.06% by weight, at least 0.07% by weight, at least0.08% by weight, at least 0.09% by weight, at least 0.1% by weight, atleast 0.15% by weight, at least 0.2% by weight, at least 0.25% byweight, at least 0.3% by weight, at least 0.35% by weight, at least 0.4%by weight, at least 0.45% by weight, at least 0.5% by weight, at least0.55% by weight, at least 0.6% by weight, at least 0.65% by weight, atleast 0.7% by weight, at least 0.75% by weight, at least 0.8% by weight,at least 0.85% by weight, at least 0.9% by weight, at least 0.95% byweight, at least 1% by weight, at least 1.25% by weight, at least 1.5%by weight, at least 1.75% by weight, at least 2% by weight, at least2.25% by weight, at least 2.5% by weight, at least 2.75% by weight, atleast 3% by weight, at least 3.25% by weight, at least 3.5% by weight,at least 3.75% by weight, at least 4% by weight, at least 4.25% byweight, at least 4.5% by weight, or at least 4.75% by weight), based onthe total weight of the LPS injection fluid. In some embodiments, thetotal concentration of all surfactants in the LPS injection fluid (thetotal concentration of the primary surfactant and the one or moresecondary surfactants in the LPS injection fluid) can be 5% by weight orless (e.g., 4.75% by weight or less, 4.5% by weight or less, 4.25% byweight or less, 4% by weight or less, 3.75% by weight or less, 3.5% byweight or less, 3.25% by weight or less, 3% by weight or less, 2.75% byweight or less, 2.5% by weight or less, 2.25% by weight or less, 2% byweight or less, 1.75% by weight or less, 1.5% by weight or less, 1.25%by weight or less, 1% by weight or less, 0.95% by weight or less, 0.9%by weight or less, 0.85% by weight or less, 0.8% by weight or less,0.75% by weight or less, 0.7% by weight or less, 0.65% by weight orless, 0.6% by weight or less, 0.55% by weight or less, 0.5% by weight orless, 0.45% by weight or less, 0.4% by weight or less, 0.35% by weightor less, 0.3% by weight or less, 0.25% by weight or less, 0.2% by weightor less, 0.15% by weight or less, 0.1% by weight or less, 0.09% byweight or less, 0.08% by weight or less, 0.07% by weight or less, 0.06%by weight or less, 0.05% by weight or less, 0.04% by weight or less,0.03% by weight or less, or 0.02% by weight or less), based on the totalweight of the LPS injection fluid.

The total concentration of all surfactants in the LPS injection fluid(the total concentration of the primary surfactant and the one or moresecondary surfactants in the LPS injection fluid) can range from any ofthe minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the totalconcentration of all surfactants in the LPS injection fluid (the totalconcentration of the primary surfactant and the one or more secondarysurfactants in the LPS injection fluid) can be from 0.01% by weight to5% by weight (e.g., from 0.01% to 2.5% by weight, from 0.01% to 1% byweight, or from 0.01% to 0.5% by weight).

In some embodiments when the LPS injection fluid is being injected intoa horizontal well, the total concentration of all surfactants in the LPSinjection fluid (the total concentration of the primary surfactant andthe one or more secondary surfactants in the LPS injection fluid) can befrom 0.01% to 1.5% by weight, from 0.01% to 1% by weight, or from 0.01%to 0.5% by weight).

In some embodiments when the LPS injection fluid is being injected intoa vertical well, the total concentration of all surfactants in the LPSinjection fluid (the total concentration of the primary surfactant andthe one or more secondary surfactants in the LPS injection fluid) can befrom 0.01% to 5% by weight, from 0.01% to 1% by weight, from 0.5% to 5%by weight, from 0.5% to 2.5% by weight, from 0.5% to 1.5% by weight,from 0.5% to 1% by weight, from 1% to 5% by weight, from 1% to 2.5% byweight, from or 1% to 1.5% by weight).

When present, the one or more co-solvents can have a concentrationwithin the low particle size injection fluid of less than 2%, less than1.5%, less than 1%, less than 0.5%, less than 0.2%, less than 0.1%, lessthan 0.075%, less than 0.05%, or less than 0.01%. For example, the oneor more co-solvents can have a concentration within the low particlesize injection fluid of from 0.001% to 1.5% by weight (e.g., 0.05% to0.5% by weight), based on the total weight of the low particle sizeinjection fluid.

After the single-phase liquid surfactant package has been combined withthe aqueous-based injection fluid, the LPS injection fluid may be asingle-phase fluid or may be an emulsion depending on the amount of oilwithin the injection fluid.

In some embodiments, the single-phase liquid surfactant package (and byextension the LPS injection fluid) can comprise a non-ionic surfactantand an anionic surfactant (e.g., a sulfonate or disulfonate). In someembodiments, the single-phase liquid surfactant package (and byextension the LPS injection fluid) can comprise a non-ionic surfactantand two or more anionic surfactants (e.g., a sulfonate or disulfonateand a carboxylate). In some embodiments, the single-phase liquidsurfactant package (and by extension the LPS injection fluid) cancomprise a non-ionic surfactant (e.g., a C6-C16 alkyl phenol ethoxylate,or a C6-C16:PO(0-25):EO(0-25), such as a C9-C11 ethoxylated alcohol, aC13 ethoxylated alcohol, a C6-C10 ethoxylated propoxylated alcohol, or aC10-C14 ethoxylated Guerbet alcohol) and a sulfonate surfactant (e.g., aC10-16 disulfonate, or a C16-28 IOS). In some embodiments, thesingle-phase liquid surfactant package (and by extension the LPSinjection fluid) can comprise a non-ionic surfactant (e.g., a C6-C16alkyl phenol ethoxylate, or a C6-16:PO(0-25):EO(0-25), such as a C9-C11ethoxylated alcohol, a C13 ethoxylated alcohol, a C6-C10 ethoxylatedpropoxylated alcohol, or a C10-C14 ethoxylated Guerbet alcohol), asulfonate surfactant (e.g., a C10-16 disulfonate, or a C16-28 IOS), anda carboxylate surfactant (e.g., a C10-16 alkyl polyglucoside carboxylateor a C22-C36 Guerbet alkoxylated carboxylate).

Specific example embodiments include the LPS injection fluids in thetable below.

LPS Surfactants and Co-Surfactants in LPS Injection Injection FluidFluid (in weight percent) 1 0.09% alkoxylated C6-C16 alcohol 0.06%disulfonate 2 0.1% alkoxylated C6-C16 alcohol 0.1% carboxylate 0.1%disulfonate 3 0.15% alkoxylated C6-C16 alcohol 0.075% carboxylate 0.075%disulfonate 4 0.2% alkoxylated C6-C16 alcohol 0.1% carboxylate 5 0.2%alkoxylated C6-C16 alcohol 0.033% carboxylate 0.066% disulfonate 6 0.2%alkoxylated C6-C16 alcohol 0.033% carboxylate 0.066% disulfonate 7 0.2%alkoxylated C6-C16 alcohol 0.05% carboxylate 0.05% olefin sulfonate 80.15% alkoxylated C6-C16 alcohol 0.05% carboxylate 0.05% olefinsulfonate 0.05% alkyl polyglucoside 9 0.1% alkoxylated C6-C16 alcohol0.05% carboxylate 0.05% olefin sulfonate 0.1% alkyl polyglucoside 100.15% alkoxylated C6-C16 alcohol 0.07% carboxylate 0.03% olefinsulfonate 0.1% alkyl polyglucoside 11 0.1% alkoxylated C6-C16 alcohol0.04% carboxylate 0.05% olefin sulfonate 0.03% disulfonate 0.1% alkylpolyglucoside 12 0.1% alkoxylated C6-C16 alcohol 0.04% carboxylate 0.06%disulfonate 0.1% alkyl polyglucoside 13 0.15% alkoxylated C6-C16 alcohol0.15% alkoxylated alkylphenol 0.1% olefin sulfonate 0.1% Guerbetalkoxylated carboxylate 14 0.125% alkoxylated C6-C16 alcohol 0.175%alkoxylated alkylphenol 0.1% olefin sulfonate 0.1% Guerbet alkoxylatedcarboxylate 15 0.1% alkoxylated C6-C16 alcohol 0.2% alkoxylatedalkylphenol 0.1% olefin sulfonate 0.1% Guerbet alkoxylated carboxylate16 0.12% alkoxylated C6-C16 alcohol 0.22% alkoxylated alkylphenol 0.08%olefin sulfonate 0.08% Guerbet alkoxylated carboxylate 17 0.15%alkoxylated C6-C16 alcohol 0.15% alkoxylated alkylphenol 0.08% olefinsulfonate 0.06% Guerbet alkoxylated carboxylate 0.06% carboxylate 180.15% alkoxylated C6-C16 alcohol 0.15% alkoxylated alkylphenol 0.05%olefin sulfonate 0.1% Guerbet alkoxylated carboxylate 0.05% disulfonate19 0.5% olefin sulfonate 0.5% Guerbet alkoxylated carboxylate 0.55%glycosides or glucosides 20 0.5% olefin sulfonate 0.5% Guerbetalkoxylated carboxylate 0.5% glycosides or glucosides 0.25% alkoxylatedC6-C16 alcohol 21 0.5% olefin sulfonate 0.5% Guerbet alkoxylatedcarboxylate 0.5% glycosides or glucosides 0.5% alkoxylated C6-C16alcohol 22 0.5% olefin sulfonate 0.5% Guerbet alkoxylated carboxylate 1%glycosides or glucosides 0.5% alkoxylated C6-C16 alcohol 23 0.05% olefinsulfonate 0.05% Guerbet alkoxylated carboxylate 0.05% glycosides orglucosides 0.05% alkoxylated C6-C16 alcohol 24 0.075% glycosides orglucosides 0.075% alkoxylated C6-C16 alcohol 25 0.1% alkoxylated C6-C16alcohol 0.05% disulfonate 26 0.1% alkoxylated C6-C16 alcohol 0.05%disulfonate 0.03% hydroxyalkyl alkylammonium chloride 27 0.03% olefinsulfonate 0.04% Guerbet alkoxylated carboxylate 0.08% glycosides orglucosides 0.05% alkoxylated C6-C16 alcohol 28 0.4% olefin sulfonate0.4% Guerbet alkoxylated carboxylate 0.7% glycosides or glucosides 0.5%alkoxylated C6-C16 alcohol 29 0.05% olefin sulfonate 0.1% glycosides orglucosides 0.05% alkoxylated C6-C16 alcohol 30 0.05% olefin sulfonate0.1% alkyl polyglucoside 0.05% alkoxylated C6-C16 alcohol 31 0.05%olefin sulfonate 0.1% glycosides or glucosides 0.05% alkoxylated C6-C16alcohol 32 0.05% olefin sulfonate 0.1% alkyl polyglucoside 0.05%alkoxylated C6-C16 alcohol 33 0.05% olefin sulfonate 0.1% alkylpolyglucoside 0.05% alkoxylated C6-C16 alcohol 34 0.05% olefin sulfonate0.05% glycosides or glucosides 0.05% alkoxylated C6-C16 alcohol 0.05%carboxylate 35 0.05% olefin sulfonate 0.05% glycosides or glucosides0.05% alkoxylated C6-C16 alcohol 0.05% carboxylate 36 0.05% olefinsulfonate 0.05% alkyl polyglucoside 0.05% alkoxylated C6-C16 alcohol 370.06% olefin sulfonate 0.05% alkyl polyglucoside 0.04% alkoxylatedC6-C16 alcohol 38 0.04% olefin sulfonate 0.08% glycosides or glucosides0.05% alkoxylated C6-C16 alcohol 0.03% disulfonate 39 0.035% olefinsulfonate 0.075% glycosides or glucosides 0.05% alkoxylated C6-C16alcohol 0.04% disulfonate 40 0.035% olefin sulfonate 0.07% glycosides orglucosides 0.045% alkoxylated C6-C16 alcohol 0.05% disulfonate 41 0.1%alkoxylated C6-C16 alcohol 0.1% disulfonate 42 0.25% Guerbet alkoxylatedcarboxylate 0.25% olefin sulfonate 0.5% glycosides or glucosides 0.5%co-solvent 43 0.075% alkoxylated C12-C22 alcohol 0.075% disulfonate 440.075% alkoxylated C6-C16 Guerbet alcohol 0.075% disulfonate 45 0.075%alkoxylated C6-C16 Guerbet alcohol 0.075% disulfonate 46 0.075%alkoxylated C6-C16 alcohol 0.075% disulfonate 47 0.075% disulfonate0.075% alkoxylated C6-C16 alcohol 48 0.0625% disulfonate 0.0875%alkoxylated C6-C16 alcohol 49 0.055% disulfonate 0.095% alkoxylatedC6-C16 alcohol 50 0.075% disulfonate 0.075% alkoxylated C6-C16 alcohol51 1% alkoxylated C6-C16 alcohol 0.5% disulfonate 52 1% alkoxylatedC6-C16 alcohol 53 1% alkoxylated C6-C16 alcohol 2.25% sulfosuccinate 540.25% Guerbet alkoxylated carboxylate 1% alkoxylated C6-C16 alcohol2.25% sulfosuccinate 55 0.25% Guerbet alkoxylated carboxylate 1%alkoxylated alkylphenol 2.25% sulfosuccinate 56 0.25% Guerbetalkoxylated carboxylate 1% alkoxylated C6-C16 alcohol 57 0.25 Guerbetalkoxylated carboxylate 1% alkoxylated alkylphenol 58 0.65% carboxylate0.35% alkoxylated C6-C16 alcohol 59 0.325% carboxylate 0.925%alkoxylated C6-C16 alcohol 60 0.25% olefin sulfonate 1.0% alkoxylatedC6-C16 alcohol 61 0.15% olefin sulfonate 0.2% Guerbet alkoxylatedcarboxylate 0.92% carboxylate 62 0.65% carboxylate 0.35% secondcarboxylate 63 0.65% carboxylate 0.35% alkoxylated C6-C16 alcohol 1%olefin sulfonate 64 1% alkoxylated alcohol 1% olefin sulfonate 65 0.5%alkoxylated alcohol 0.5% olefin sulfonate 0.25% carboxylate 66 0.6%co-solvent 0.6% olefin sulfonate 67 0.6% co-solvent 0.3% disulfonate0.3% olefin sulfonate 68 0.6% Guerbet alkoxylated carboxylate 0.6%disulfonate 69 0.6% co-solvent 0.4% disulfonate 0.2% olefin sulfonate 700.5% alkoxylated C6-C16 alcohol 0.4% disulfonate 0.3% olefin sulfonate71 1% alkoxylated C6-C16 alcohol 72 0.9% alkoxylated C6-C16 alcohol 0.6%disulfonate 73 0.4% alkoxylated C6-C16 alcohol 0.35% disulfonate 0.25%olefin sulfonate 0.5% co-solvent 74 0.25% Guerbet alkoxylatedcarboxylate 0.5% alkoxylated C6-C16 alcohol 0.35% disulfonate 0.15%olefin sulfonate 0.35% co-solvent 75 0.25% Guerbet alkoxylatedcarboxylate 0.25% alkoxylated C6-C16 alcohol 0.25% olefin sulfonate0.25% co-solvent 76 0.25% Guerbet alkoxylated carboxylate 0.25%alkoxylated C6-C16 alcohol 0.25% olefin sulfonate 0.25% alkoxylatedalcohol 77 0.25% Guerbet alkoxylated carboxylate 0.35% olefin sulfonate0.5% alkoxylated alcohol 78 0.25% Guerbet alkoxylated carboxylate 0.25%alkoxylated C6-C16 alcohol 0.15% olefin sulfonate 0.1% disulfonate 0.25%co-solvent 79 0.25% Guerbet alkoxylated carboxylate 0.25% alkoxylatedC6-C16 alcohol 0.25% olefin sulfonate 0.25% glycosides or glucosides0.25% co-solvent 0.15% disulfonate 80 0.25% Guerbet alkoxylatedcarboxylate 0.25% olefin sulfonate 0.5% glycosides or glucosides 0.25%co-solvent 81 0.15% alkoxylated C12-C22 alcohol 82 0.075% alkoxylatedC12-C22 alcohol 0.075% disulfonate 83 0.075% alkoxylated C12-C22 alcohol0.075% disulfonate 84 0.075% alkoxylated C12-C22 alcohol 0.075%alkoxylated C6-C16 Guerbet alcohol 85 0.15% alkoxylated C6-C16 Guerbetalcohol 86 0.075% alkoxylated C6-C16 Guerbet alcohol 0.075% disulfonate87 0.075% alkoxylated C6-C16 Guerbet alcohol 0.075% disulfonate 0.05%co-solvent 88 0.1% alkoxylated C6-C16 alcohol 0.05% disulfonate 89 1%alkoxylated C6-C16 alcohol 0.5% disulfonate 90 0.075% alkoxylated C6-C16Guerbet alcohol 0.075% disulfonate 91 0.075% alkoxylated C6-C16 Guerbetalcohol 0.125% disulfonate 92 0.075% alkoxylated C12-C22 alcohol 0.125%disulfonate 93 0.075% alkoxylated C12-C22 alcohol 0.075% disulfonate 940.075% alkoxylated C6-C16 Guerbet alcohol 0.075% disulfonate 95 0.1%alkoxylated C6-C16 Guerbet alcohol 0.05% disulfonate 96 0.075%alkoxylated C6-C16 Guerbet alcohol 0.075% disulfonate 97 0.075%alkoxylated C6-C16 alcohol 0.075% disulfonate 98 0.075% alkoxylatedC6-C16 Guerbet alcohol 0.075% disulfonate 99 0.1% alkoxylated C6-C16alcohol 0.05% disulfonate 100 0.09% alkoxylated C6-C16 alcohol 0.06%disulfonate 101 0.1% alkoxylated C6-C16 alcohol 0.1% disulfonate 0.1%Guerbet alkoxylated carboxylate 102 0.1% alkoxylated C6-C16 alcohol 0.1%disulfonate 103 0.65% Guerbet alkoxylated carboxylate 0.35% olefinsulfonate 0.33% alkoxylated alkylphenol 0.5% co-solvent 0.25% secondco-solvent 104 0.075% alkoxylated C6-C16 alcohol 0.075% benzenesulfonicacid, decyl(sulfophenoxy)-disodium salt 105 0.15% alkoxylated C6-C16alcohol 0.05% benzenesulfonic acid, decyl(sulfophenoxy)-disodium salt

In some embodiments, the primary surfactant and the one or moresecondary surfactants can be added to the aqueous-based injection fluidto form the LPS injection fluid. For example, the primary surfactant andthe one or more secondary surfactants can be pre-mixed as components ofthe single-phase liquid surfactant package. Alternatively, the primarysurfactant and the one or more secondary surfactants can be separatelycombined with (e.g., sequentially added to) the aqueous-based injectionfluid to form the LPS injection fluid. In other embodiments, the primarysurfactant and/or the one or more secondary surfactants can be addedseparately or together to an aqueous-based injection fluid whenpreparing slickwater in a tank. In some embodiments, the primarysurfactant and the one or more secondary surfactants can be mixed withone or more additional components prior to combination with theaqueous-based injection fluid.

The one or more surfactants present in the single-phase liquidsurfactant package (and ultimately the LPS injection fluid) can beselected to improve hydrocarbon recovery. Specifically, the one or moresurfactants can improve hydrocarbon recovery by increasing the aqueousstability of the LPS injection fluid at the temperature and salinity ofthe reservoir, decreasing the interfacial tension (IFT) of the LPSinjection fluid with hydrocarbons in the reservoir, changing (e.g.,increasing or decreasing the wettability of the reservoir, or anycombination thereof.

In some embodiments, the one or more surfactants in the single-phaseliquid surfactant package (and ultimately the LPS injection fluid) canincrease the aqueous stability of the LPS injection fluid at thetemperature and salinity of the reservoir. Aqueous stable solutions canpropagate further into a reservoir upon injection as compared to aninjection fluid lacking aqueous stability. In addition, because injectedchemicals remain soluble aqueous stable solutions, aqueous stablesolutions do not precipitate particulates or phase separate within theformation which may obstruct or hinder fluid flow through the reservoir.As such, injection fluids that exhibit aqueous stability under reservoirconditions can largely eliminate formation damage associated withprecipitation of injected chemicals. In this way, hydrocarbon recoverycan be facilitated by the one or more surfactants in the single-phaseliquid surfactant package.

In some embodiments, the one or more surfactants in the single-phaseliquid surfactant package (and ultimately the LPS injection fluid) candecrease the interfacial tension (IFT) of the LPS injection fluid withhydrocarbons in the reservoir. Reducing the IFT can decrease pressurerequired to drive an aqueous-based injection fluid into the formationmatrix. In addition, decreasing the IFT reduces water block duringproduction, facilitating the flow of hydrocarbons from the formation tothe wellbore (e.g., facilitating the flow of hydrocarbons back throughthe fractures and to the wellbore). In this way, hydrocarbon recoverycan be facilitated by the one or more surfactants in the single-phaseliquid surfactant package.

In some embodiments, the one or more surfactants in the single-phaseliquid surfactant package (and ultimately the LPS injection fluid) canchange the wettability of the reservoir. In particular, in embodimentswhere the reservoir is oil-wet or mixed-wet, the one or more surfactantsin the single-phase liquid surfactant package (and ultimately the LPSinjection fluid) can make the reservoir more water-wet. By increasingthe water-wetness of the reservoir, the formation will imbibe injectedaqueous-based injection fluid into the formation matrix, leading to acorresponding flow of hydrocarbon from regions within the formation backto the fracture. In this way, hydrocarbon recovery can be facilitated bythe one or more surfactants in the single-phase liquid surfactantpackage.

In some embodiments, the one or more surfactants can improve hydrocarbonrecovery by increasing the aqueous stability of the LPS injection fluidat the temperature and salinity of the reservoir and decreasing theinterfacial tension (IFT) of the LPS injection fluid with hydrocarbonsin the reservoir. In some embodiments, the one or more surfactants canimprove hydrocarbon recovery by decreasing the interfacial tension (IFT)of the LPS injection fluid with hydrocarbons in the reservoir andincreasing the wettability of the reservoir. In some embodiments, theone or more surfactants can improve hydrocarbon recovery by increasingthe aqueous stability of the LPS injection fluid at the temperature andsalinity of the reservoir and increasing the wettability of thereservoir. In certain embodiments, the one or more surfactants canimprove hydrocarbon recovery by increasing the aqueous stability of theLPS injection fluid at the temperature and salinity of the reservoir,decreasing the interfacial tension (IFT) of the LPS injection fluid withhydrocarbons in the reservoir, and changing the wettability of thereservoir.

METHODS

Embodiments for the process for running treatment operations in anunconventional formation with a LPS injection fluid will now bedescribed. The LPS injection fluid can be used during any portion (orduring the entirety of) a treatment operation.

In some embodiments, the LPS injection fluid can be used as part of acompletion and/or fracturing operation. For example, the LPS injectionfluid can be injected into an unconventional subterranean formation toform and/or extend fractures within the formation. In certainembodiments, the fracturing operation can comprise combining asingle-phase liquid surfactant package described herein with anaqueous-based injection fluid to form a low particle size injectionfluid; and injecting the low particle size injection fluid through awellbore and into the unconventional subterranean formation at asufficient pressure and at a sufficient rate to fracture theunconventional subterranean formation. In some embodiments, the wellboreis a hydraulic fracturing wellbore associated with a hydraulicfracturing well, for example, that may have a substantially verticalportion only, or a substantially vertical portion and a substantiallyhorizontal portion below the substantially vertical portion. In someembodiments, the fracturing operation can be performed in a new well(e.g., a well that has not been previously fractured). In otherembodiments, the LPS injection fluid can be used in a fracturingoperation in an existing well (e.g., in a refracturing operation).

In some embodiments, the method can comprise performing a fracturingoperation on a region of the unconventional subterranean formationproximate to a new wellbore. In some embodiments, the method cancomprise performing a fracturing operation on a region of theunconventional subterranean formation proximate to an existing wellbore.In some embodiments, the method can comprise performing a refracturingoperation on a previously fractured region of the unconventionalsubterranean formation proximate to a new wellbore. In some embodiments,the method can comprise performing a refracturing operation on apreviously fractured region of the unconventional subterranean formationproximate to an existing wellbore. In some embodiments, the method cancomprise performing a fracturing operation on a naturally fracturedregion of the unconventional subterranean formation proximate to a newwellbore (e.g., an infill well). In some embodiments, the method cancomprise performing a fracturing operation on a naturally fracturedregion of the unconventional subterranean formation proximate to anexisting wellbore.

In cases where the fracturing method comprises a refracturing methods,the previously fractured region of the unconventional reservoir can havebeen fractured by any suitable type of fracturing operation. Forexample, the fracturing operation may include hydraulic fracturing,fracturing using electrodes such as described in U.S. Pat. No. 9,890,627(Attorney Dkt. No. T-9622A), U.S. Pat. No. 9,840,898 (Attorney Dkt. No.T-9622B), U.S. Patent Publication No. 2018/0202273 (Attorney Dkt. No.T-9622A-CIP), or fracturing with any other available equipment ormethodology. In some embodiments, the fracturing operation can furthercomprise adding a tracer to the low particle size injection fluid priorto introducing the low particle size injection fluid through thewellbore into the unconventional subterranean formation; recovering thetracer from the fluids produced from the unconventional subterraneanformation through the wellbore, fluids recovered from a differentwellbore in fluid communication with the unconventional subterraneanformation, or any combination thereof; and comparing the quantity oftracer recovered from the fluids produced to the quantity of tracerintroduced to the low particle size injection fluid. The tracer cancomprise a proppant tracer, an oil tracer, a water tracer, or anycombination thereof. Example tracers are known in the art, anddescribed, for example, in U.S. Pat. No. 9,914,872 and Ashish Kumar etal., Diagnosing Fracture-Wellbore Connectivity Using Chemical TracerFlowback Data, URTeC 2902023, Jul. 23-25, 2018, page 1-10, Texas, USA.

The LPS injection fluids can be used at varying points throughout afracturing operation. For example, the LPS injection fluid can be usedas an injection fluid during the first, middle or last part of thefracturing process, or throughout the entire fracturing process. In someembodiments, the fracturing process can include a plurality of stagesand/or sub-stages. For example, the fracturing process can involvesequential injection of fluids in different stages, with each of thestages employing a different aqueous-based injection fluid system (e.g.,with varying properties such as viscosity, chemical composition, etc.).Example fracturing processes of this type are described, for example, inU.S. Patent Application Publication Nos. 2009/0044945 and 2015/0083420,each of which is hereby incorporated herein by reference in itsentirely.

In these embodiments, the LPS injection fluid can be used as aninjection fluid (optionally with additional components) during any orall of the stages and/or sub-stages. Stages and/or sub-stages can employa wide variety of aqueous-based injection fluid systems, includinglinear gels, crosslinked gels, and friction-reduced water. Linear gelfracturing fluids are formulated with a wide array of different polymersin an aqueous base. Polymers that are commonly used to formulate theselinear gels include guar, hydroxypropyl guar (HPG), carboxymethyl HPG(CMHPG), and hydroxyethyl cellulose (HEC). Crosslinked gel fracturingfluids utilize, for example, borate ions to crosslink the hydratedpolymers and provide increased viscosity. The polymers most often usedin these fluids are guar and HPG. The crosslink obtained by using borateis reversible and is triggered by altering the pH of the fluid system.The reversible characteristic of the crosslink in borate fluids helpsthem clean up more effectively, resulting in good regained permeabilityand conductivity. The single-phase liquid surfactant packages describedherein can be added to any of these aqueous-based injection fluidsystems.

In some embodiments, the single-phase liquid surfactant package can becombined with an aqueous-based injection fluid in a continuous processto form the LPS injection fluid (which is subsequently injected). Inother embodiments, the single-phase liquid surfactant package can beintermittently added to an aqueous-based injection fluid, therebyproviding the LPS injection fluid only during desired portions of thetreatment operation (e.g., during one or more phases or stages of afracturing operation). For example, the single-phase liquid surfactantpackage could be added when injecting slickwater, when injectingfracturing fluid with proppant, during an acid wash, or during anycombination thereof. In a specific embodiment, the single-phase liquidsurfactant package is continuously added to the aqueous injection fluidafter acid injection until completion of hydraulic fracturing andcompletion fluid flow-back. When intermittently dosed, the single-phaseliquid surfactant package can be added to the aqueous-based injectionfluid once an hour, once every 2 hours, once every 4 hours, once every 5hours, once every 6 hours, twice a day, once a day, or once every otherday, for example. In some embodiments when used in a fracturingoperation, the low particle size injection fluid can have a totalsurfactant concentration of from 0.01% to 1% by weight, based on thetotal weight of the low particle size injection fluid.

In some embodiments, the LPS injection fluid can be used as part of areservoir stimulation operation. In such operations, the fluid can beinjected to alter the wettability of existing fractures within theformation (without further fracturing the formation significantly byeither forming new fractures within the formation and/or extending theexisting fractures within the formation). In such stimulationoperations, no proppant is used, and fluid injection generally occurs ata lower pressure.

In some cases, the existing fractures can be naturally occurringfractures present within a formation. For example, in some embodiments,the formation can comprise naturally fractured carbonate or naturallyfractured sandstone. The presence or absence of naturally occurringfractures within a subterranean formation can be assessed using standardmethods known in the art, including seismic surveys, geology, outcrops,cores, logging, reservoir characterization including preparing grids,etc.

In some embodiments, methods for stimulating an unconventionalsubterranean formation with a fluid can comprise introducing a lowparticle size injection fluid described through a wellbore into theunconventional subterranean formation; allowing the low particle sizeinjection fluid to imbibe into a rock matrix of the unconventionalsubterranean formation for a period of time; and producing fluids fromthe unconventional subterranean formation through the wellbore. The lowparticle size injection fluid can comprise an aqueous based injectionfluid and an anionic surfactant comprising a hydrophobic tail comprisingfrom 6 to 60 carbon atoms. The low particle size injection fluid canhave a maximum particle size of less than 0.1 micrometers in diameter inparticle size distribution measurements performed at a temperature andsalinity of the unconventional subterranean formation. In these methods,the same wellbore can be used for both introducing the LPS injectionfluid and producing fluids from the unconventional subterraneanformation. In some embodiments, introduction of the LPS injection fluidcan increase the production of hydrocarbons from the same wellbore, froma different wellbore in fluid communication with the unconventionalsubterranean formation, or any combination thereof.

In some embodiments, the stimulation operation can further comprisepreparing the LPS injection fluid. For example, in some embodiments, thestimulation operation can further comprise combining a single-phaseliquid surfactant package described herein with an aqueous-basedinjection fluid to form a low particle size injection fluid.

In some embodiments when used in a stimulation operation, the lowparticle size injection fluid can have a total surfactant concentrationof from 0.2% to 5% by weight, based on the total weight of the lowparticle size injection fluid.

In some embodiments, introducing a low particle size injection fluiddescribed through a wellbore into the unconventional subterraneanformation can comprise injecting the low particle size injection fluidthrough the wellbore and into the unconventional subterranean formationat a sufficient pressure and at a sufficient rate to stimulatehydrocarbon production from naturally occurring fractures in theunconventional subterranean formation.

The low particle size injection fluid can be allowed to imbibe into therock matrix of the unconventional subterranean formation for varyingperiods of time depending on the nature of the rock matrix. The imbibingcan occur during the introducing step, between the introducing andproducing step, or any combination thereof. In some examples, the lowparticle size injection fluid can be allowed to imbibe into the rockmatrix of the unconventional subterranean formation for at least one day(e.g., at least two days, at least three days, at least four days, atleast five days, at least six days, at least one week, at least twoweeks, at least three weeks, at least one month, at least two months, atleast three months, at least four months, or at least five months). Insome examples, the low particle size injection fluid can be allowed toimbibe into the rock matrix of the unconventional subterranean formationfor six months or less (e.g., five months or less, four months or less,three months or less, two months or less, one month or less, three weeksor less, two weeks or less, one week or less, six days or less, fivedays or less, four days or less, three days or less, or two days orless).

The low particle size injection fluid can be allowed to imbibe into therock matrix of the unconventional subterranean formation for a period oftime ranging from any of the minimum values described above to any ofthe maximum values described above. For example, the low particle sizeinjection fluid can be allowed to imbibe into the rock matrix of theunconventional subterranean formation for from one day to six months. Inone example, the wellbore can be a new wellbore; and the low particlesize injection fluid can be allowed to imbibe into the rock matrix ofthe unconventional subterranean formation for from two weeks to onemonth. In another example, the wellbore can be a wellbore proximate to apreviously fractured region of the unconventional subterraneanformation; and the low particle size injection fluid can be allowed toimbibe into the rock matrix of the unconventional subterranean formationfor from one day to two weeks.

In some embodiments, the wellbore used in the stimulation operation mayhave a substantially vertical portion only, or a substantially verticalportion and a substantially horizontal portion below the substantiallyvertical portion.

In some embodiments, the stimulation methods described herein cancomprise stimulating a naturally fractured region of the unconventionalsubterranean formation proximate to a new wellbore (e.g., an infillwell). In some embodiments, the stimulation methods described herein cancomprise stimulating a naturally fractured region of the unconventionalsubterranean formation proximate to an existing wellbore.

In some embodiments, the stimulation methods described herein cancomprise stimulating a previously fractured or previously refracturedregion of the unconventional subterranean formation proximate to a newwellbore (e.g., an infill well). In some embodiments, the stimulationmethods described herein can comprise stimulating a previously fracturedor previously refractured region of the unconventional subterraneanformation proximate to an existing wellbore.

The previous fracturing operation may include hydraulic fracturing,fracturing using electrodes such as described in U.S. Pat. No. 9,890,627(Attorney Dkt. No. T-9622A), U.S. Pat. No. 9,840,898 (Attorney Dkt. No.T-9622B), U.S. Patent Publication No. 2018/0202273 (Attorney Dkt. No.T-9622A-CIP), or fracturing with any other available equipment ormethodology. The previous refracturing operation may include hydraulicfracturing, fracturing using electrodes such as described in U.S. Pat.No. 9,890,627 (Attorney Dkt. No. T-9622A), U.S. Pat. No. 9,840,898(Attorney Dkt. No. T-9622B), U.S. Patent Publication No. 2018/0202273(Attorney Dkt. No. T-9622A-CIP), or refracturing with any otheravailable equipment or methodology. In some embodiments, after aformation that has fractures, such as naturally occurring factures,fractures from a fracture operation, fractures from a refracturingoperation, or any combination thereof, the fractured formation may bestimulated. For example, a formation may be stimulated after asufficient amount of time has passed since the fracturing operation withelectrodes or refracturing operation with electrodes occurred in thatformation so that the electrical pulses utilized to fracture orrefracture that formation do not substantially affect the LPS injectionfluid.

In some embodiments, the stimulation operation can further compriseadding a tracer to the low particle size injection fluid prior tointroducing the low particle size injection fluid through the wellboreinto the unconventional subterranean formation; recovering the tracerfrom the fluids produced from the unconventional subterranean formationthrough the wellbore, fluids recovered from a different wellbore influid communication with the unconventional subterranean formation, orany combination thereof; and comparing the quantity of tracer recoveredfrom the fluids produced to the quantity of tracer introduced to the lowparticle size injection fluid.

Single-phase liquid surfactant packages (as well as the resulting LPSinjection fluids) can be optimized for each unconventional reservoirand/or for the type of aqueous-based injection fluid. For example, asingle-phase liquid surfactant package can be tested at a specificreservoir temperature and salinity, and with a specific aqueous-basedinjection fluid. Actual native reservoir fluids may also be used to testthe compositions. In an embodiment, the single-phase liquid surfactantpackage is tested by determining the mean particle size distributionthrough dynamic light scattering. In specific embodiments, the meanparticle size distribution of the aqueous-based injection fluiddecreases after addition of the single-phase liquid surfactant package.In embodiments, the average diameter of particle size of the LPSinjection fluid (aqueous-based injection fluid plus single-phase liquidsurfactant package) is less than 0.1 micrometers. In an embodiment, whentested at the specific reservoir temperature and salinity, the averagediameter of the LPS injection fluid is less than 0.1 micrometers. Inspecific embodiments, the average diameter in particle size distributionmeasurement of the LPS injection fluid is less than the average poresize of the unconventional reservoir rock matrix.

In some embodiments, the unconventional subterranean formation can havea temperature of at least 75° F. (e.g., at least 80° F., at least 85°F., at least 90° F., at least 95° F., at least 100° F., at least 105°F., at least 110° F., at least 115° F., at least 120° F., at least 125°F., at least 130° F., at least 135° F., at least 140° F., at least 145°F., at least 150° F., at least 155° F., at least 160° F., at least 165°F., at least 170° F., at least 175° F., at least 180° F., at least 190°F., at least 200° F., at least 205° F., at least 210° F., at least 215°F., at least 220° F., at least 225° F., at least 230° F., at least 235°F., at least 240° F., at least 245° F., at least 250° F., at least 255°F., at least 260° F., at least 265° F., at least 270° F., at least 275°F., at least 280° F., at least 285° F., at least 290° F., at least 295°F., at least 300° F., at least 305° F., at least 310° F., at least 315°F., at least 320° F., at least 325° F., at least 330° F., at least 335°F., at least 340° F., or at least 345° F.). In some embodiments, theunconventional subterranean formation can have a temperature of 350° F.or less (e.g., 345° F. or less, 340° F. or less, 335° F. or less, 330°F. or less, 325° F. or less, 320° F. or less, 315° F. or less, 310° F.or less, 305° F. or less, 300° F. or less, 295° F. or less, 290° F. orless, 285° F. or less, 280° F. or less, 275° F. or less, 270° F. orless, 265° F. or less, 260° F. or less, 255° F. or less, 250° F. orless, 245° F. or less, 240° F. or less, 235° F. or less, 230° F. orless, 225° F. or less, 220° F. or less, 215° F. or less, 210° F. orless, 205° F. or less, 200° F. or less, 195° F. or less, 190° F. orless, 185° F. or less, 180° F. or less, 175° F. or less, 170° F. orless, 165° F. or less, 160° F. or less, 155° F. or less, 150° F. orless, 145° F. or less, 140° F. or less, 135° F. or less, 130° F. orless, 125° F. or less, 120° F. or less, 115° F. or less, 110° F. orless, 105° F. or less, 100° F. or less, 95° F. or less, 90° F. or less,85° F. or less, or 80° F. or less).

The unconventional subterranean formation can have a temperature rangingfrom any of the minimum values described above to any of the maximumvalues described above. For example, in some embodiments, theunconventional subterranean formation can have a temperature of from 75°F. to 350° F. (approximately 24° C. to 176° C.), from 150° F. to 250° F.(approximately 66° C. to 121° C.), from 110° F. to 350° F.(approximately 43° C. to 176° C.), from 110° F. to 150° F.(approximately 43° C. to 66° C.), from 150° F. to 200° F. (approximately66° C. to 93° C.), from 200° F. to 250° F. (approximately 93° C. to 121°C.), from 250° F. to 300° F. (approximately 121° C. to 149° C.), from300° F. to 350° F. (approximately 149° C. to 176° C.), from 110° F. to240° F. (approximately 43° C. to 116° C.), or from 240° F. to 350° F.(approximately 116° C. to 176° C.).

In some embodiments, the salinity of unconventional subterraneanformation can be at least 5,000 ppm TDS (e.g., at least 25,000 ppm TDS,at least 50,000 ppm TDS, at least 75,000 ppm TDS, at least 100,000 ppmTDS, at least 125,000 ppm TDS, at least 150,000 ppm TDS, at least175,000 ppm TDS, at least 200,000 ppm TDS, at least 225,000 ppm TDS, atleast 250,000 ppm TDS, or at least 275,000 ppm TDS). In someembodiments, the salinity of unconventional subterranean formation canbe 300,000 ppm TDS or less (e.g., 275,000 ppm TDS or less, 250,000 ppmTDS or less, 225,000 ppm TDS or less, 200,000 ppm TDS or less, 175,000ppm TDS or less, 150,000 ppm TDS or less, 125,000 ppm TDS or less,100,000 ppm TDS or less, 75,000 ppm TDS or less, 50,000 ppm TDS or less,or 25,000 ppm TDS or less).

The salinity of unconventional subterranean formation can range from anyof the minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the salinity ofunconventional subterranean formation can be from 5,000 ppm TDS to300,000 ppm TDS (e.g., from 100,000 ppm to 300,000 ppm TDS).

In some embodiments, the unconventional subterranean formation can beoil-wet. In some embodiments, the unconventional subterranean formationcan be water-wet. In some embodiments, the unconventional subterraneanformation can be mixed-wet.

In some embodiments, the LPS injection fluid can be introduced at awellhead pressure of at least 0 PSI (e.g., at least 1,000 PSI, at least2,000 PSI, at least 3,000 PSI, at least 4,000 PSI, at least 5,000 PSI,at least 6,000 PSI, at least 7,000 PSI, at least 8,000 PSI, at least9,000 PSI, at least 10,000 PSI, at least 15,000 PSI, at least 20,000PSI, or at least 25,000 PSI). In some embodiments, the LPS injectionfluid can be introduced at a wellhead pressure of 30,000 PSI or less(e.g., 25,000 PSI or less, 20,000 PSI or less, 15,000 PSI or less,10,000 PSI or less, 9,000 PSI or less, 8,000 PSI or less, 7,000 PSI orless, 6,000 PSI or less, 5,000 PSI or less, 4,000 PSI or less, 3,000 PSIor less, 2,000 PSI or less, or 1,000 PSI or less).

The LPS injection fluid can be introduced at a wellhead pressure rangingfrom any of the minimum values described above to any of the maximumvalues described above. For example, in some embodiments, the LPSinjection fluid can be introduced at a wellhead pressure of from 0 PSIto 30,000 PSI (e.g., from 6,000 PSI to 30,000 PSI, or from 5,000 PSI to10,000 PSI. In some embodiments, the LPS fluid can be used in areservoir stimulation operation, and the LPS injection fluid can beintroduced at a wellhead pressure of from 0 PSI to 1,000 PSI.

Example embodiments of using a LPS injection fluid in a wellbore will bedescribed more fully hereinafter with reference to the accompanyingdrawings, in which example embodiments of injecting an LPS injectionfluid into a wellbore are shown. The injection, however, may be embodiedin many different forms and should not be construed as limited to theexample embodiments set forth herein. Rather, these example embodimentsare provided so that this disclosure will be thorough and complete, andwill fully convey the scope of injecting an LPS injection fluid into anunconventional reservoir to those of ordinary skill in the art. Like,but not necessarily the same, elements in the various figures aredenoted by like reference numerals for consistency.

FIGS. 2A-2C illustrate an example injection using the LPS injectionfluid of the disclosure. A single-phase liquid surfactant package ismixed into an aqueous-based injection fluid prior to injection into aportion of an unconventional reservoir forming a LPS injection fluid.The LPS injection fluid is then pumped into a well under pressure suchthat the LPS injection fluid penetrates the rock matrix (FIG. 2A priorto injection, FIG. 2B after injection). Because the LPS injection fluiddoes not precipitate out when inside the unconventional reservoir,insoluble particles are minimized. After fracturing or stimulating thereservoir there is increased transmissibility and improved productivitydue to less damage from trapped particles that precipitated out ofsolution (FIG. 2C) than would be encountered in reservoirs treated withprior art injection fluids (FIG. 1C). Furthermore, in some embodiments,the LPS injection fluid penetrates deeper into the formation rock matrixcompared to prior injection fluids due to the addition of thesingle-phase liquid surfactant package.

FIG. 3A is a schematic illustration of system and method 300A forpreparing LPS injection fluids for use in a variety of operations,including the fracturing and/or completion of new wells usingsingle-phase liquid surfactant packages. Aqueous based injection fluidis provided at unit 310. Unit 310 can be any means for providingsufficient amounts of aqueous based injection fluid, e.g., for ahydraulic fracturing operation. In some embodiments, unit 310 comprisesmultiple portable storage units (commonly referred to as “frac tanks”).Each frac tank holds approximately 20,000 gallons of aqueous basedinjection fluid and are delivered via truck trailer. Aqueous basedinjection fluid is supplied to a gel hydration unit 320 to mix andhydrate polymer. Gel hydration unit 320 is often partitioned into aplurality of hydration sections to ensure complete hydration of thepolymer. Pump 330 pumps the aqueous based injection fluid from gelhydration unit 320 to blender 340. Proppant from proppant storage unit350 can be delivered to blender 340 where it is mixed with the aqueousbased injection fluid. The slurry exiting blender 340 can berecirculated via pump 360 back into blender or the aqueous basedinjection fluid can proceed towards injection.

Various chemicals can be added to the aqueous based injection fluid toincrease performance of the fracturing operation. For example, in FIG.3A, a biocide is added to aqueous based injection fluid at point A;gelling agent, gelling stabilizers and buffers, scale inhibitor andbiocide are added at point B; friction reducer, a breaker, andsurfactant buffer are added at point C; and a crosslinker is added atpoint D. In other embodiments, these chemicals—or other chemicals suchas an acid, a pH adjusting agent, a non-emulsifier agent, a scaleinhibitor, an iron control agent, a corrosion inhibitor, a claystabilizing agent, a proppant, or any combination thereof—can beintroduced in different locations to prepare aqueous based injectionfluid for injection.

Single-phase liquid surfactant package 370 comprising a primarysurfactant is combined with the aqueous based injection fluid after theblender 340 and prior to fracture pump 390 to form a low particle sizeinjection fluid. Combining single-phase liquid surfactant package 370with the aqueous based injection fluid downstream of the blender 340helps avoid foaming, which is a common phenomenon encountered in mixingprocesses as surfactants can cause or exacerbate the foam formation. Inalternative embodiments, the single-phase liquid surfactant package 370can be added upstream of blender 340. Here, the addition of an anti-foamagent (e.g., chemical defoamer) can be applied to destroy and/or avoidfoam formation. A sample of the low particle size injection fluid can betaken at sampling unit 380 to confirm low particle size injection fluidmeets fluid specifications (e.g., viscosity, aqueous stability, chemicalconcentrations). The low particle injection fluid is introduced into theunconventional subterranean formation 400 via wellbore 410 after beingpressurized by fracture pump 390. Fracture pump 390 is a pumping unitthat can deliver the low particle injection fluid into wellbore 410 atsufficient rates and volumes to increase the pressure at a targetlocation (e.g., determined by the location of casing perforations inwellbore 410) such that the pressure exceeds the fracture gradient ofthe reservoir rock, thereby creating or extending fractures 420 in therock matrix of unconventional subterranean formation 400. The wellbore410 can include one or more valves 430 at the wellhead of wellbore 410.Valves 430 can be used to stop fluid flow between wellbore 410 and thehigh pressure line connecting fracture pump 390. For example, valves 430can be closed following injection of the pressurized low particleinjection fluid into wellbore 410 (e.g., to isolate fluid from flowbackas it is produced back up wellbore 410 and is being routed to flowbacktank (not shown)).

FIG. 3B is a schematic illustration of system and method 300B forpreparing LPS injection fluids for use in the stimulation of existingwells (i.e., where fracturing and/or completion of a well has alreadytaken place). Here, the conventional surface blending system used insystem and method 300A is not needed for the preparation of LPS.Instead, the process is simplified and single-phase liquid surfactantpackage 370 comprising a primary surfactant is combined with the aqueousbased injection fluid from unit 310 to form a low particle sizeinjection fluid. Various chemicals can be added to the aqueous basedinjection fluid at point A to increase performance of the stimulationoperation. For example, a biocide, a scale inhibitor, a pH adjustingagent, a non-emulsifier agent, an iron control agent, a corrosioninhibitor, or any combination thereof can be added to aqueous basedinjection fluid at point A. In alternative embodiments, these chemicalscan be provided in single-phase liquid surfactant package 370.

EXAMPLES

The invention will be described in greater detail by way of specificexamples. The following examples are offered for illustrative purposes,and are not intended to limit the invention in any manner. Those ofskill in the art will readily recognize a variety of non-criticalparameters which can be changed or modified to yield essentially thesame results.

Example 1

As detailed below, three different injection fluid chemistries wereutilized: slickwater, an acid spearhead comprising aqueous basedinjection fluid with 15% hydrochloric (HCl) acid, and an aqueous basedinjection fluid with linear gel (diluted at 15 lb/Mgal) with across-linker. Stages 4-9 of the example fracturing operation alsocontained a 100 mesh proppant and stages 11-12 utilized a 40/70 meshcurable resin coated (CRC) proppant.

TABLE 1 Stages of an example fracturing operation. Aqueous-Based PumpRate Pump Time Stage Injection Fluid Proppant (bpm) (min) 1 Slickwater —5 2.4 2 15% HCl Acid — 15 3.2 3 Slickwater — 40 7.7 4 Slickwater 100mesh 80 7.0 5 Slickwater 100 mesh 80 8.6 6 Slickwater 100 mesh 80 12.4 7Slickwater 100 mesh 85 14.5 8 Slickwater 100 mesh 85 14.7 9 Slickwater100 mesh 85 13.6 10 15# Linear Gel 100 mesh 85 13.8 11 15# Linear Gel40/70 CRC 85 7.3 12 15# Linear Gel 40/70 CRC 85 16.4 13 15# Linear Gel85 0.6 14 Slickwater 85 3.1

A schematic illustration of the method for preparing injection fluidswith single-phase liquid surfactant packages is shown in FIG. 3A.Briefly, the aqueous-based injection fluids were prepared conventionallyand additional materials (e.g., gelling agent, proppant) were mixed withthe aqueous-based injection fluids in a blender. The single-phase liquidsurfactant package was added to the aqueous-based injection fluidsdownstream of the blending unit to form the LPS injection fluid. Onceformed, the LPS injection fluid can be pressurized and introducedthrough a wellbore and into the unconventional reservoir.

Sampling of injection fluids used as the aqueous base fluid in thisexample were conducted just downstream of the blending unit. Other thanfrom the low pressure side of the frac-manifold, this is the lastlocation in which samples could be collected at low pressure(approximately 100 PSI) before being charged to over 8,000 PSI.Injection fluid samples were taken from a sampling line connected to thedischarge manifold of the blending unit. The primary components of thetest setup were a hot-water bath, thermocouple with digital readout,scale, stirplate and filtration apparatus.

Different single-phase liquid surfactant packages were tested forcompatibility against the treatment schedule of a fracture completion inan example unconventional reservoir. To characterize compatibilityrequired testing three different injection fluid chemistries:slickwater; a low-polymer, borate-crosslinked fracturing fluid includinga sand-based proppant; and an acid spearhead comprising an aqueous basedinjection fluid with 15% hydrochloric (HCl) acid.

Prescreening for slickwater compatibility. The first set of prescreeningexperiments was performed using slickwater from the fourth sub-stage ofa completion. The constituents of the fluid sample collected included: afriction reducing polymer transported in emulsion form, asurfactant/solvent mixture to prevent emulsion formation, and fieldinjection water (approximately 7,500 ppm via refractometry). Theslickwater sample had the consistency of water and an opaque appearance.This fluid was not aqueous stable at ambient conditions and also provedto be unstable at reservoir temperature (approximately 75° C. or 167°F.).

Different single-phase liquid surfactant packages were added to theslickwater sample at prescribed concentrations and heated in a waterbath to 75° C. (167° F.). Temperature was set and displayed on the waterbath and was confirmed using a thermocouple with digital readout.

Three single-phase liquid surfactant packages enhanced the clarity ofthe unfiltered slickwater sample at reservoir temperature (shown in FIG.4, from left to right: SPLC1, SPLC2, SPLC3, and slickwater only). TheSPLC1 formulation showed superior performance relative to the samplegroup. SPLC2 also showed excellent performance. SPLC3 showed the nextbest performance. The SPLC3 formulation was slightly hazy and itsperformance was likely boosted due to a higher dilution ratio than theother samples tested. The SPLC1, 2 and 3 formulations containeddisulfonates as anionic surfactant. A single-phase liquid surfactantpackage (SPLC4) with internal olefin sulfonate also successfullyclarified unfiltered slickwater at reservoir temperature (FIG. 11).

TABLE 2 Composition of four example single-phase liquid surfactantpackages evaluated herein. Formation Additives (wt % desired ininjection fluid) SPLC1 C9-11 ethoxylated alcohol (1%) benzenesulfonicacid, decyl(sulfophenoxy)- disodium salt (0.5%) SPLC2 C9-11 ethoxylatedalcohol (0.75%) benzenesulfonic acid, decyl(sulfophenoxy)- disodium salt(0.75%) SPLC3 Cl2-14 secondary ethoxylated alcohol (0.75%),benzenesulfonic acid, decyl(sulfophenoxy)- disodium salt (0.75%) SPLC4C12-14 secondary ethoxylated alcohol (0.075%) C16-18 Internal olefinSulfonate (IOS) (0.075%)

Embodiments of the ethoxylated alcohols tested in these examples rangedfrom 8-20 EO groups. However, in embodiments of the disclosure,ethoxylated alcohols could range from 1-100 EO groups.

SPLC1 was tested further for compatibility under increased salinity. Asthe injection fluid moves down-hole, through fractures and away from thewellbore, it encounters reservoir brine. This occurs during flow-back aswell. Formation water salinity can exceed 100,000 ppm TDS. Thisincreased salinity challenges aqueous stability. Experiments wereconducted to observe the potential impact of increased salinity onSPLC1. Sodium chloride (NaCl) was added to unfiltered slickwater samplescontaining SPLC1 at its prescribed concentration and then heated to 75°C. (167° F.). The results of this sensitivity experiment are shown belowin FIG. 5.

The SPLC1 composition proved quite resilient. Even when 100,000 ppm NaCl(+10 wt % NaCl) was added to the solution, bringing the TDS of thesolution to 107,500 ppm, the SPLC1 remained aqueous stable at 75° C.(167° F.). Somewhere between 107,500 ppm (+10 wt % NaCl) and 157,500 ppm(+15 wt % NaCl), aqueous stability was lost and the solution becamefoggy in appearance. As a side note, cooling the 157,500 ppm sample (+15wt % NaCl) down to 61° C. (142° F.) returned the sample's aqueousstability.

The SPLC1 formulation was tested further to investigate how aqueousstability held up when the prescribed chemical package concentration wasreduced. The results of this experiment are shown in FIG. 6. SPLC1 wasdiluted to 0.750 wt % and 0.375 wt % in unfiltered slickwater. At 0.750wt %, SPLC1 remained aqueous stable. A slight haze developed when theSPLC1 concentration was reduced to 0.375 wt %.

Gel and Cross-linker Compatibility. The next water chemistry prescreenedwas an injection fluid whose primary additive constituents were gellingagent (HPAM) and cross-linker. A detailed constituent list follows:

Petroleum distillates, Gelling Agent

Non-Emulsifier Agent

Ammonium Persulfate, Breaker

Boric acid with ethylene glycol and monoethanolamine, Crosslinker

pH Adjusting Agent

Field Injection Water (approximately 7,500 ppm via refractometry)

30/50 mesh (300 μm-600 μm) White Sand, Proppant

Conducting compatibility and aqueous stability tests with the fracturingfluid proved very challenging. The sample was extremely viscous,containing sand, polymer and an active crosslinker. A photograph of thesample collected is shown below in FIG. 7. Due to its viscosity and thefact that polymer contained in the sample was actively beingcrosslinked, the sample could not be filtered. Testing with unfilteredfracturing fluid was conducted using the leading single-phase liquidsurfactant packages previously identified from slickwater compatibilitytesting.

Despite the presence of degrading polymer, the procedure forprescreening the single-phase liquid surfactant packages provedfruitful. The SPLC1 formulation clarified the fracturing fluid sample tosome degree over the control.

15% HCl Acid Compatibility. The last injection fluid chemistryprescreened was the 15% HCl Acid spearhead. Each fracture completionstage is typically initiated with an acid spearhead to assist inbreaking down the formation. The acid spearhead contains the followingcomponents:

15% HCl Acid

Scale, corrosion, and biological inhibitors

Acetic acid, Iron Control Agent

Citric acid, Iron Control Agent

Non-Emulsifier Agent

Field Injection Water (approximately 7,500 ppm via refractometry)

The purpose of this testing was to determine whether the SPLC woulddropout or cause precipitation in the acid spearhead. Should this occur,in embodiments, a bicarbonate buffer could be added to protect the SPLCpackage from the acid spearhead. If the SPLC chemical package remainedstable then the added complexity associated with a buffer solution maynot be needed.

HCl is delivered on-site at a 20% concentration and injected at a 15%concentration. This means that upon injection, the HCl is only slightlydiluted with field brine. This results in a slightly cleaner, but stillnot aqueous stable, injection fluid. The pH was tested at about 1 pH.This extremely low pH could ultimately break apart surfactant molecules.

The most fragile surfactant in SPLC1 formulation is ethoxylatedalcohols. An ethoxylated alcohol was added to the 15% HCl Acid at itsprescribed concentration. The sample was then heated to 75° C. (167°F.). After heating for 3 days, the chemical stability of the surfactantwas tested using high-performance liquid chromatography (HPLC) and itshowed that there was not significant surfactant degradation with 15%HCl (FIG. 13).

The SPLC1 formulation exhibited superior performance when prescreenedrelative to the dozens of engineered chemical packages, additives andcombinations thereof that were tested for field injection fluidscompatibility and aqueous stability. These compatibility tests wereperformed for three injection water chemistries present during afracturing operation. Additional sensitivity studies of the SPLC1formulation revealed aqueous stability in excess of 107,500 ppm TDS inSlickwater. Compatibility testing in a fracturing fluid showed promisingresults for the SPLC1 formulation. HPLC data showed that ethoxylatedalcohol in SPLC1 formulation is chemical stable in 15% HCl Acid atelevated temperature. SPLC's stability in acid eliminates the need for abuffer solution which simplifies piloting operations. Furthersensitivity of the SPLC1 formulation showed aqueous stability atconcentrations below 0.750%.

Example 2

The particle size distribution of injection fluids was measured with alaser diffraction particle size analyzer (Horiba la 300, minimummeasurement of 0.1 μm diameter). Slickwater and slickwater plusdifferent amounts of anionic surfactant and/or non-ionic surfactantswere measured after mixing and resting overnight at 75° C. (167° F.).

FIG. 8 shows the particle size measurement of the field slickwater onlysample (solid line with average particle size diameter around 13 μm);field slickwater plus 0.1% C9-11 ethoxylated alcohol (non-ionicsurfactant) (dashed line with average particle size diameter around 8.0μm); and field slickwater plus 0.05% benzenesulfonic acid,decyl(Sulfophenoxy)-disodium salt (anionic surfactant; solid linestraight through 0 μm indicating a particle size of the solution is lessthan the minimum measurement of 0.1 μm diameter of the instrument). Theslickwater plus anionic surfactant sample had no particle sizes with adiameter higher than 0.1 μm, which is the smallest diameter theinstrument could measure.

FIG. 9 shows the particle size measurement of the field slickwater onlysample (solid line with average particle size around 13 μm); fieldslickwater plus 0.1% C9-11 ethoxylated alcohol and 0.05% benzenesulfonicacid, decyl(Sulfophenoxy)-disodium salt (non-ionic and anionicsurfactant; dashed straight line through 0 μm indicating a particle sizeof the solution is less than the minimum measurement of instrument of0.1 μm diameter); and field slickwater plus 0.075% Guerbet C10ethoxylated alcohol and 0.075% benzenesulfonic acid,decyl(Sulfophenoxy)-disodium salt (non-ionic and anionic surfactant;dotted line straight through 0 μm indicating a particle size of thesolution is less than the minimum measurement of 0.1 μm diameter).Accordingly, both slickwater plus anionic and nonionic surfactantmixtures resulted in a particle size measurements of at least less than0.1 μm.

FIG. 10 shows the particle size measurement of the field slickwater onlysample (solid line with mean particle size around 13 μm), slickwaterplus 0.075% Guerbet C10 ethoxylate alcohol (non-ionic surfactant, dashedline with average particle size diameter around 2.5 μm); and fieldslickwater plus 0.075% benzenesulfonic acid,decyl(Sulfophenoxy)-disodium salt (anionic surfactant; solid linestraight through 0 μm indicating a particle size measurement is lessthan the minimum measurement of 0.1 μm diameter of the instrument). Theslickwater plus anionic surfactant sample had no particle sizes with adiameter higher than 0.1 μm.

FIG. 12 shows the particle size measurement of the field slickwater onlysample (solid line with average particle size around 13 μm); slickwaterplus 0.075% Guerbet C10 ethoxylated alcohol and 0.075% C16-18 internalolefin sulfonate (non-ionic and anionic surfactant; indicating aparticle size of the solution is less than the minimum measurement ofthe instrument of 0.1 μm diameter); and field slickwater plus 0.075%C16-18 internal olefin sulfonate (anionic surfactant; solid linestraight through 0 μm indicating a particle size of the solution is lessthan the minimum measurement of 0.1 μm diameter). Both slickwater plusanionic surfactant mixture and slickwater plus anionic-nonionicsurfactant mixture resulted in a particle size measurements of at leastless than 0.1 μm.

Example 3

A field example was performed in five horizontal wells in a NorthAmerican unconventional subterranean formation. The wells had previouslybeen fractured and had been producing 6-12 months. A low particle sizeinjection fluid was injected into four horizontal wells and an aqueousbased injection fluid was injected into the fifth horizontal well (i.e.,the fifth well was merely used as a comparison well and did not utilizethe low particle size injection fluid). The aqueous based injectionfluid comprised a brine having 5,000 ppm total dissolved solids (nofracturing fluids were used with the exception of a liquid additivebiocide). The low particle size injection fluid was formed by combininga single-phase liquid surfactant package with the aqueous basedinjection fluid using the surface facility setup illustrated in FIG. 3B.Injection was performed at low flow rates over several days in anattempt to not refracture any of the wells. No injectivity issues wereobserved for any of the wells during injection. After injection and asoak period, production was resumed.

FIG. 14 provides a graph of fluid production at a tank battery level,which encompasses the five horizontal wells in this example. The dotsrepresent crude oil flow production and the solid line represents adecline curve extrapolation fit that was performed for the tank batteryprior to injection in this example. No new wells were added to the tankbattery during the duration of this example and it is believed that theincremental oil recovered (represented by the area between the dots andthe decline curve extrapolation) is a result primarily from the LPSfluid injected. The comparison well with only brine injection showed aninitial uptick in oil production, but the oil production rate begandeclining back to what appeared to be the well's original decline curve.Whereas, the four wells injected with the LPS injection fluid showedsustained increases in oil production over the course of observation.

FIG. 15 shows tracer response curves for the five wells in this example.The comparison well with brine injection is shown in solid line and theLPS injected wells are shown in dashed lines. Injection fluid for eachwell was traced with a different chemical tracer in efforts to diagnoseand interpret fluid production results. Tracer concentrations weremeasured from produced fluid samples. The quantity of tracer chemicalsrecovered compared to the total quantity injected for the comparisonwell with brine injection was much higher compared to the four wellsinjected with LPS fluid. It is believed that there was less tracerrecovered from the wells injected with LPS fluids as they had a lowerinterfacial tension (IFT) compared to brine allowing them to imbibefurther into the rock matrix of the unconventional subterraneanreservoir and they were also able to alter the rock wettability to amore water-wet state, thus displacing additional crude oil from regionswithin the formation to the fractures.

The description and illustration of one or more embodiments provided inthis application are not intended to limit or restrict the scope of theinvention as claimed in any way. The embodiments, examples, and detailsprovided in this disclosure are considered sufficient to conveypossession and enable others to make and use the best mode of theclaimed invention. The claimed invention should not be construed asbeing limited to any embodiment, example, or detail provided in thisapplication. Regardless of whether shown and described in combination orseparately, the various features (both structural and methodological)are intended to be selectively included or omitted to produce anembodiment with a particular set of features. Having been provided withthe description and illustration of the present application, one skilledin the art may envision variations, modifications, and alternateembodiments falling within the spirit of the broader aspects of theclaimed invention and the general inventive concept embodied in thisapplication that do not depart from the broader scope. For instance,such other examples are intended to be within the scope of the claims ifthey have structural or methodological elements that do not differ fromthe literal language of the claims, or if they include equivalentstructural or methodological elements with insubstantial differencesfrom the literal language of the claims, etc. All citations referred toherein are expressly incorporated by reference.

What is claimed is:
 1. A method for treating an unconventionalsubterranean formation with a fluid, comprising: (a) combining asingle-phase liquid surfactant package comprising a primary surfactantwith an aqueous-based injection fluid to form a low particle sizeinjection fluid; and (b) introducing the low particle size injectionfluid into the unconventional subterranean formation; wherein theprimary surfactant comprises an anionic surfactant comprising ahydrophobic tail comprising from 6 to 60 carbon atoms, and wherein thelow particle size injection fluid has a maximum particle size of lessthan 0.1 micrometers in diameter in particle size distributionmeasurements performed at a temperature and salinity of theunconventional subterranean formation.
 2. The method of claim 1, whereinthe low particle size injection fluid further comprises a proppant, andwherein the maximum particle size of less than 0.1 micrometers isexclusive of the proppant.
 3. The method of any of claims 1-2, whereinthe primary surfactant comprises a sulfonate, a disulfonate, apolysulfonate, a sulfate, a disulfate, a polysulfate, a sulfosuccinate,a disulfosuccinate, a polysulfosuccinate, a carboxylate, adicarboxylate, a polycarboxylate, or any combination thereof.
 4. Themethod of any of claims 1-3, wherein the primary surfactant comprises abranched or unbranched C6-C32:PO(0-65):EO(0-100)-carboxylate.
 5. Themethod of any of claims 1-4, wherein the primary surfactant comprises abranched or unbranched C6-C30:PO(30-40):EO(25-35)-carboxylate.
 6. Themethod of any of claims 1-5, wherein the primary surfactant comprises abranched or unbranched C6-C12:PO(30-40):EO(25-35)-carboxylate.
 7. Themethod of any of claims 1-4, wherein the primary surfactant comprises abranched or unbranched C6-C30:EO(8-30)-carboxylate.
 8. The method of anyof claims 1-3, wherein the primary surfactant comprises a surfactantdefined by the formula belowR¹—R²—R³ wherein R¹ comprises a branched or unbranched, saturated orunsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32carbon atoms and an oxygen atom linking R¹ and R²; R² comprises analkoxylated chain comprising at least one oxide group selected from thegroup consisting of ethylene oxide, propylene oxide, butylene oxide, andcombinations thereof; and R³ comprises a branched or unbranchedhydrocarbon chain comprising 2-12 carbon atoms and from 2 to 5carboxylate groups.
 9. The method of any of claims 1-3, wherein theprimary surfactant comprises a C10-C30 internal olefin sulfonate, aC8-C30 alkyl benzene sulfonate (ABS), a sulfosuccinate surfactant, orany combination thereof.
 10. The method of any of claims 1-3, whereinthe primary surfactant comprises a surfactant defined by the formulabelow

wherein R⁴ is a branched or unbranched, saturated or unsaturated, cyclicor non-cyclic, hydrophobic carbon chain having 6-32 carbon atoms; and Mrepresents a counterion.
 11. The method of any of claims 1-10, whereinthe primary surfactant comprises from 10% to 90% by weight of thesingle-phase liquid surfactant package.
 12. The method of any of claims1-11, the aqueous-based injection fluid comprises sea water, brackishwater, fresh water, flowback or produced water, wastewater, river water,lake or pond water, aquifer water, brine, or any combination thereof.13. The method of any of claims 1-12, wherein the primary surfactant hasa concentration within the low particle size injection fluid of lessthan 1%, less than 0.5%, less than 0.2%, less than 0.1%, less than0.075%, or less than 0.05% by weight, based on the total weight of thelow particle size injection fluid.
 14. The method of any of claims 1-12,wherein the primary surfactant has a concentration within the lowparticle size injection fluid of from 0.05% to 0.5% by weight, based onthe total weight of the low particle size injection fluid.
 15. Themethod of any of claims 1-14, wherein the single-phase liquid surfactantpackage further comprises one or more secondary surfactants.
 16. Themethod of claim 15, wherein the one or more secondary surfactantscomprise a non-ionic surfactant.
 17. The method of claim 16, wherein thenon-ionic surfactant comprises a branched or unbranchedC6-C32:PO(0-65):EO(0-100).
 18. The method of any of claims 16-17,wherein the non-ionic surfactant comprises a branched or unbranchedC6-C30:PO(30-40):EO(25-35).
 19. The method of any of claims 16-18,wherein the non-ionic surfactant comprises a branched or unbranchedC6-C12:PO(30-40):EO(25-35).
 20. The method of any of claims 16-17,wherein the non-ionic surfactant comprises a branched or unbranchedC6-C30:EO(8-30).
 21. The method of any of claims 16-20, wherein thenon-ionic surfactant has a hydrophilic-lipophilic balance of greaterthan
 10. 22. The method of any of claims 15-21, wherein the one or moresecondary surfactants comprise an anionic surfactant.
 23. The method ofany of claims 15-22, wherein the one or more secondary surfactantscomprise a cationic surfactant.
 24. The method of any of claims 15-23,wherein the one or more secondary surfactants comprise a zwitterionicsurfactant.
 25. The method of any of claims 15-24, wherein the one ormore secondary surfactants comprise from 10% to 90% by weight of thesingle-phase liquid surfactant package.
 26. The method of any of claims15-25, wherein the one or more secondary surfactants have aconcentration within the low particle size injection fluid of less than1%, less than 0.5%, less than 0.2%, less than 0.1%, less than 0.075%, orless than 0.05%.
 27. The method of any of claims 15-26, wherein the oneor more secondary surfactants have a concentration within the lowparticle size injection fluid of from 0.05% to 0.5% by weight, based onthe total weight of the low particle size injection fluid.
 28. Themethod of any of claims 1-27, wherein combination of the single-phaseliquid surfactant package with the aqueous-based injection fluid lowersthe particle size distribution of the aqueous-based injection fluid whenmeasured at the temperature and salinity of the unconventionalsubterranean formation.
 29. The method of any of claims 1-28, whereinthe low particle size injection fluid is introduced at a wellheadpressure of from 0 PSI to 30,000 PSI.
 30. The method of claim 29,wherein the low particle size injection fluid is introduced at awellhead pressure of from 6,000 PSI to 30,000 PSI.
 31. The method ofclaim 29, wherein the low particle size injection fluid is introduced ata wellhead pressure of from 5,000 PSI to 10,000 PSI.
 32. The method ofany of claims 1-31, wherein the unconventional subterranean formationhas a temperature of from 75° F. to 350° F.
 33. The method of claim 32,wherein the unconventional subterranean formation has a temperature offrom 150° F. to 250° F.
 34. The method of any of claims 1-33, whereinthe unconventional subterranean formation has a salinity of at least5,000 ppm TDS.
 35. The method of claim 34, wherein the unconventionalsubterranean formation has a salinity of at least 100,000 ppm TDS. 36.The method of any of claims 34-35, wherein the unconventionalsubterranean formation has a salinity of from 100,000 ppm to 300,000 ppmTDS.
 37. The method of any of claims 1-36, wherein the unconventionalsubterranean formation has a permeability of less than 25 mD.
 38. Themethod of claim 37, wherein the unconventional subterranean formationhas a permeability of from 10 to 0.1 millidarcy (mD).
 39. The method ofany of claims 1-38, wherein the low particle size injection fluid is asingle-phase fluid.
 40. The method of any of claims 1-39, wherein themean particle size distribution of the low particle size injection fluidis less than an average pore size of a rock matrix in the unconventionalsubterranean formation.
 41. The method of any of claims 1-40, whereinthe low particle size injection fluid further comprises an acid.
 42. Themethod of any of claims 1-41, wherein the low particle size injectionfluid further comprises a friction reducer, a gelling agent, acrosslinker, a breaker, a pH adjusting agent, a non-emulsifier agent, aniron control agent, a corrosion inhibitor, a scale inhibitor, a biocide,a clay stabilizing agent, a proppant, or any combination thereof. 43.The method of any of claims 1-42, wherein the low particle sizeinjection fluid further comprises a wettability alteration chemical. 44.The method of any of claims 1-43, wherein the single-phase liquidsurfactant package further comprises one or more co-solvents.
 45. Themethod of claim 44, wherein the one or more co-solvents comprise a C1-C5alcohol, an ethoxylated C1-C5 alcohol, or any combination thereof. 46.The method of any of claims 1-45, wherein the mean particle sizedistribution of the low particle size injection fluid is less than 0.05micrometer in diameter when measured at the temperature and salinity ofthe unconventional subterranean formation.
 47. The method of any ofclaims 1-46, wherein the aqueous-based injection fluid has a meanparticle size distribution of greater than 10 micrometers prior to theaddition of the single-phase liquid surfactant package.
 48. The methodof any of claims 1-47, wherein the mean particle size distribution ofthe low particle size injection fluid is at least 10 micrometers smallerthan a mean particle size distribution of the aqueous-based injectionfluid.
 49. The method of any of claims 1-48, wherein the low particlesize injection fluid precipitates out fewer solid particles than theaqueous-based injection fluid when introduced into the rock matrix. 50.The method of any of claims 1-49, wherein the aqueous-based injectionfluid comprises slickwater.
 51. The method of any of claims 1-50,wherein the aqueous-based injection fluid comprises at least 10% acid.52. The method of any of claims 1-51, wherein the aqueous-basedinjection fluid comprises a friction reducer, an acid, a gelling agent,a crosslinker, a breaker, a pH adjusting agent, a non-emulsifier agent,an iron control agent, a corrosion inhibitor, a scale inhibitor, abiocide, a clay stabilizing agent, a proppant, or any combinationthereof.
 53. The method of any of claims 1-52, wherein the methodcomprises a hydraulic fracturing operation.
 54. The method of claim 53,step (b) comprises injecting the low particle size injection fluidthrough a wellbore and into the unconventional subterranean formation ata sufficient pressure and at a sufficient rate to fracture theunconventional subterranean formation.
 55. The method of claim 54,wherein the wellbore comprises a vertical trajectory.
 56. The method ofclaim 54, wherein the wellbore comprises a horizontal trajectory. 57.The method of any of claims 53-56, wherein method comprises performing afracturing operation on a region of the unconventional subterraneanformation proximate to a new wellbore.
 58. The method of any of claims53-56, wherein method comprises performing a fracturing operation on aregion of the unconventional subterranean formation proximate to anexisting wellbore.
 59. The method of any of claims 53-56, wherein themethod comprises performing a refracturing operation on a previouslyfractured region of the unconventional subterranean formation proximateto a new wellbore.
 60. The method of any of claims 53-56, wherein themethod comprises performing a refracturing operation on a previouslyfractured region of the unconventional subterranean formation proximateto an existing wellbore.
 61. The method of any of claims 53-56, whereinmethod comprises performing a fracturing operation on a naturallyfractured region of the unconventional subterranean formation proximateto a new wellbore.
 62. The method of any of claims 53-56, wherein methodcomprises performing a fracturing operation on a naturally fracturedregion of the unconventional subterranean formation proximate to anexisting wellbore.
 63. The method of any of claims 53-58, wherein thelow particle size injection fluid has a total surfactant concentrationof from 0.01% to 1% by weight, based on the total weight of the lowparticle size injection fluid.
 64. The method of any of claims 1-52,wherein the method comprises a formation stimulation operation.
 65. Themethod of any of claims 1-64, wherein the unconventional subterraneanformation comprises an oil-wet reservoir.
 66. The method of any ofclaims 1-64, wherein the unconventional subterranean formation comprisesa water-wet reservoir.
 67. A method for treating an unconventionalsubterranean formation with a fluid, comprising: providing anaqueous-based injection fluid for treating the unconventionalsubterranean formation, the unconventional subterranean formation havinga rock matrix with an average pore size less than 0.1 micrometers;adding an anionic surfactant to the aqueous-based injection fluid toform a low particle size injection fluid; and introducing the lowparticle size injection fluid into the rock matrix of the unconventionalsubterranean formation, wherein the low particle size injection fluidhas a maximum particle size of less than 0.1 micrometers in diameterparticle size distribution measurement when measured at a temperatureand salinity of the unconventional subterranean formation.
 68. Themethod of claim 67, wherein the mean particle size distribution of thelow particle size injection fluid is less than 0.05 micrometers indiameter when measured at the temperature and salinity of theunconventional subterranean formation.
 69. The method of claim any ofclaims 67-68, wherein the aqueous-based injection fluid has a meanparticle size distribution of greater than 10 micrometers prior to theaddition of the anionic surfactant.
 70. The method of any of claims67-69, wherein the mean particle size distribution of the low particlesize injection fluid is at least 10 micrometers smaller than a meanparticle size distribution of the aqueous-based injection fluid.
 71. Themethod of any of claims 67-70, wherein the low particle size injectionfluid precipitates out fewer solid particles than that of theaqueous-based injection fluid when introduced into the rock matrix. 72.The method of any of claims 67-71, wherein the aqueous-based injectionfluid comprises slickwater.
 73. The method of any of claims 67-72,wherein the aqueous-based injection fluid comprises at least 10% acid.74. The method of any of claims 67-73, wherein the aqueous-basedinjection fluid comprises a friction reducer, an acid, a gelling agent,a crosslinker, a breaker, a pH adjusting agent, a non-emulsifier agent,an iron control agent, a corrosion inhibitor, a biocide, a claystabilizing agent, a proppant, or any combination thereof.
 75. Themethod of any of claims 67-74, wherein the low particle size injectionfluid is a single-phase liquid.
 76. The method of any of claims 67-75,wherein the anionic surfactant comprises a sulfonate, a disulfonate, apolysulfonate, a sulfate, a disulfate, a polysulfate, a sulfosuccinate,a disulfosuccinate, a polysulfosuccinate, a carboxylate, adicarboxylate, a polycarboxylate, or any combination thereof.
 77. Themethod of claim 76, wherein the anionic surfactant comprises adisulfonate.
 78. The method of any of claims 67-77, wherein the anionicsurfactant is in a single-phase liquid when added to the aqueous-basedinjection fluid.
 79. The method of any of claims 67-78, wherein themethod further comprises adding one or more non-ionic surfactants to theaqueous based injection fluid or low particle size injection fluid. 80.A method for fracturing an unconventional subterranean formation with afluid, comprising: (a) combining a single-phase liquid surfactantpackage comprising a primary surfactant with an aqueous-based injectionfluid to form a low particle size injection fluid; and (b) injecting thelow particle size injection fluid through a wellbore and into theunconventional subterranean formation at a sufficient pressure and at asufficient rate to fracture the unconventional subterranean formation;wherein the primary surfactant comprises an anionic surfactantcomprising a hydrophobic tail comprising from 6 to 60 carbon atoms, andwherein the low particle size injection fluid has a maximum particlesize of less than 0.1 micrometers in diameter in particle sizedistribution measurements performed at a temperature and salinity of theunconventional subterranean formation.
 81. The method of claim 80,wherein the low particle size injection fluid further comprises aproppant, and wherein the maximum particle size of less than 0.1micrometers is exclusive of the proppant.
 82. The method of any ofclaims 80-81, wherein the wellbore comprises a vertical trajectory. 83.The method of any of claims 80-81, wherein the wellbore comprises ahorizontal trajectory.
 84. The method of any of claims 80-83, whereinmethod comprises performing a fracturing operation on a region of theunconventional subterranean formation proximate to a new wellbore. 85.The method of any of claims 80-83, wherein method comprises performing afracturing operation on a region of the unconventional subterraneanformation proximate to an existing wellbore.
 86. The method of any ofclaims 80-83, wherein the method comprises performing a refracturingoperation on a previously fractured region of the unconventionalsubterranean formation proximate to a new wellbore.
 87. The method ofany of claims 80-83, wherein the method comprises performing arefracturing operation on a previously fractured region of theunconventional subterranean formation proximate to an existing wellbore.88. The method of any of claims 80-83, wherein method comprisesperforming a fracturing operation on a naturally fractured region of theunconventional subterranean formation proximate to a new wellbore. 89.The method of any of claims 80-83, wherein method comprises performing afracturing operation on a naturally fractured region of theunconventional subterranean formation proximate to an existing wellbore.90. The method of any of claims 80-89, wherein the low particle sizeinjection fluid has a total surfactant concentration of from 0.01% to 1%by weight, based on the total weight of the low particle size injectionfluid.
 91. The method of any of claims 80-90, wherein the method furthercomprises producing fluids from the unconventional subterraneanformation through the wellbore.
 92. The method of claim 91, wherein thefluids comprise a hydrocarbon.
 93. The method of any of claims 80-92,wherein the method further comprises: adding a tracer to the lowparticle size injection fluid prior to introducing the low particle sizeinjection fluid through the wellbore into the unconventionalsubterranean formation; recovering the tracer from the fluids producedfrom the unconventional subterranean formation through the wellbore,fluids recovered from a different wellbore in fluid communication withthe unconventional subterranean formation, or any combination thereof;and comparing the quantity of tracer recovered from the fluids producedto the quantity of tracer introduced to the low particle size injectionfluid.